A Case Study of the Power Section in India

Indira Gandhi Institute of Development Research Bombay, India /N/fcX'DK'" ~

Environmentally sound energy efficient strategies: a case study of the power sector in India

Prof. Jyoti Parikh Dr. J.P. Painuly Dr. Kankar Bhattacharya

Working Paper No. 6 UNEP Collaborating Centre on Energy and Environment Risp National Laboratory, Denmark February 1997 of tw tmiMBfr b wtairreD ENVIRONMENTALLY SOUND ENERGY EFFICIENT STRATEGIES A CASE STUDY OF THE POWER SECTOR IN INDIA

Working Paper No. 6

Printed by: Grafisk Service, Ris0 National Laboratory

ISBN 87-550-2285-5 ISSN 1025-2258

Prof. Jyoti Parikh Dr. J.P. Painuly Dr. Kankar Bhattacharya

Indira Gandhi Institute of Development Research Gen. Vaidya Marg, Goregaon (East) Bombay 400 065 India Tel: +91 22 840 0920/21 Fax: +91 22 840 2752/840 2026

UNEP Collaborating Centre on Energy and Environment Ris0 National Laboratory P.O. Box 49 DK-4000 Roskilde Denmark Tel: +45 46 32 22 88 Fax: +45 46 32 19 99

n DISCLAIMER

Portions of this document may be illegible in electronic image products. Images are produced from the best available original document Foreword

This report is the sixth in a series of working papers on energy and environment issues published by the UNEP Collaborating Centre on Energy and Environment at Ris0 National Laboratory, Denmark. The UNEP Collaborating Centre was established in 1990 with a primary mission of furthering the incorporation of environmental issues in energy planning and policy, particularly in developing countries. The work of the Centre is to a great extent catalytic, involving close collaboration with researchers, planners, government agencies, etc. in all parts of the world. The newsletter c2e2 news, published at regular intervals, presents short items on Centre activities and related topics. The UNEP Centre Working Papers provide a medium for extended discussion of relevant topics written by Centre staff or collaborating colleagues.

The work presented in this report follows an earlier study carried out by the Indira Gandhi Institute for Development Research. That work was published as the fourth in the series of UNEP Centre Working Papers - Environmentally Sound Energy Development Strategies for Maharashtra, J. Parikh, J.P. Painuly and K. Bhattacharya (Indira Gandhi Institute of Development Research, Bombay, India), Working Paper No. 4, December 1995. The present report documents the extension of the study to the whole of India.

Gordon A. Mackenzie

Series Editor

February 1997 IV Preface

This study was taken up by the Indira Gandhi Institute of Development Research (IGIDR) on initiative from UNEP Collaborating Centre for Energy and Environment (UCCEE), Ris0 National Laboratory. IGIDR is involved in several policy studies related to energy and environment and took up this opportunity to explore "Environmentally Sound Energy Development Strategies for the State of Maharashtra" in the phase 1 of the study. The objective of the study was to identify potential for Environmentally Sound Energy Technologies (ESETs) and provide a strategy for implementation of a few ESETs in the State, which could also be replicated by other states. The study was extended to estimate potential at all India level during the second phase. This report combines the two phases of the project.

It may be worthwhile to state that prior to this, IGIDR carried out a project on Limiting Carbon Dioxide Emissions through Economic Instruments: Applications to India and Canada, supported by Indo-Canada Link Project and carried out with North-South Institute and Conference Board of Canada, both located in Ottawa, Canada. This project report provides a policy framework for economic instruments in general and joint implementation in particular. The report pointed out that the power system is one of the most important sectors for international cooperation to reduce green-house gas (GHG) emissions.

In the present work, the technologies relating to power system are discussed since power generation is predominantly coal-based, in India, thus leading to environmental degradation and hence greater feasibility of adapting them. The study covers the following: a. Measures for reduction of Auxiliary Consumption in Thermal Power Plants, an area that has not been studied systematically so far. The study indicates substantial potential for energy savings through up-gradation of auxiliaries. b. Reduction of Transmission and Distribution (T&D) Losses in Maharashtra State Electricity Board (MSEB) system. The study throws light on the possible savings at the transmission level and recommends a field study in the distribution side to identify loss reduction measures. c. Demand Side Management (DSM) Options for HT Industries in Maharashtra have been identified. This part of the study is based on an earlier comprehensive study on DSM carried out by IGIDR for MSEB. d. Barriers in Implementation, Institutional and Financial Mechanisms required for successful implementation of suggested measures have been brought out. Actions required to be taken by various agencies have also been identified.

It is well known that losses in auxiliary operation and T&D system are significant and need to be reduced. It is also accepted that potential for savings through DSM is considerable. The present work takes up case studies to suggest how and how much can be reduced and

v provides detailed information which can be useful for future investments in this area. It thus provides concrete opportunities for further action.

The study was conducted in two phases. In the first phase two power stations of MSEB (Nasik and Parli) were studied for exploring possible measures for reduction in auxiliary consumption and evaluate the potential. The transmission and distribution losses in MSEB system, DSM options for HT industries in Maharashtra and barriers in implementation were also covered in this phase. Interim results of the study were presented to MSEB in Feb. ’94 in order to get feedback. The report of the phase 1 was submitted in October 1994.

The scope of the study was enlarged in the second phase to include case study of two more power stations outside the MSEB system. Korba Super Thermal Power Station of National Thermal Power Corporation (NTPC, a federal government utility), and Panipat Thermal Power Station of Haryana Electricity Board (a state government utility of the Haryana State) were selected to study diversity in auxiliary consumption across utilities. The second phase also included estimation of all India potential for energy and emissions savings for 200/210 MW power plants based on the above the above four case studies. It is hoped that, following this study, a plan for implementation will be prepared by the concerned agencies.

We thank UCCEE, specially Dr. Pramod Deo and Dr. John Christensen, for providing financial support for the study. The study was taken up by us on initiative from Dr. Deo, who also provided valuable help during the study. Dr. Deo also gave useful comments on the draft of the study.

We would also like to thank MSEB officials, specially Mr. M.V. Dekhne, Member (Technical), Mr. R.C. Gupta (Tech.Director) and Mr. G.G. Dalai (Dy.Chief Engineer) for their cooperation during the study. Mr. Dalai not only provided the requested information but also helped in arranging our site visits. Mr. R.G. Patil (Chief Engineer), Mr. Ghanekar (Dy.C.E), Mr. Ondkar (SE) and their colleagues provided us the valuable support in conducting field study at Nasik TPS. Mr. S.M. Phadke (Dy.C.E.) and his colleagues helped us at Parli TPS. Mr. Kukde (C.E., Koradi TPS) gave valuable comments during the interim presentation at MSEB, Bombay office.

We take this opportunity to thank Mr. S.M.C. Pillai, Director (Operations), NTPC, New Delhi, for making the plant visit to Korba STPS successful. We appreciate the help and cooperation extended by Mr. B.M. Bhattacharya, DGM (OS) and Mr. K. Ratna Rao, Manager (OS) of NTPC Western Region Headquarters, Nagpur. We thank Mr. J.N. Sinha, General Manager, Mr. S.R. Yadav, DGM (O&M), Mr. R.S. Sharma, DGM (O&M) and their colleagues at Korba STPS who were extremely helpful in providing relevant information, fruitful discussions and advice on our study, in spite of their busy schedule.

We thank Mr. J.L. Arora, Engineer-in-Chief, Panipat Thermal Power Station, for making the visit to Panipat TPS successful. We also appreciate the help and cooperation extended by Mr. A.R. Gupta, Superintendent Engineer and his colleagues at Panipat TPS.

Mr. M.V. Dekhne and Mr. J.C. Shah and Mr. Redlinger reviewed the report and gave useful comments. Mr. Dekhne specifically pointed out possibility of PF improvement in auxiliaries and proper sizing (2.9.1 and 2.9.2 was added after that). We sincerely thank him for this. We

vi appreciate the comments and discussions provided by Dr. Bhaskar Natarajan, Director, Energy Management Center, New Delhi on this study.

We also thank Mr. P. Shah for his help in the Phase 1 of the study.

Jyoti Parikh J.P. Painuly Kankar Bhattacharya

Vll Vlll Contents

Foreword ...... iii Preface ...... v Executive summary ...... xi-xx

Part I: Background

1 Introduction ...... 1 1.1 Environmental impacts of energy related activities in India: a review of studies ...... 2 1.2 Brief review of the performance of Indian power sector...... 3 1.3 Environmentally sound technologies; supply side options ...... 8 1.4 Scope of the study...... 9

Part II: Supply side management options

2 Reduction of auxiliary consumption from thermal power stations ...... 11 2.1 Introduction ...... 11 2.2 Analysis of trends in auxiliary consumption in India ...... 11 2.3 Unit capacity-wise share of generating capacity and energy generation in India ...... 14 2.4 Reasons for high auxiliary consumption ...... 16 2.5 Equipment-wise breakup of auxiliary consumption in thermal power station ...... 16 2.6 Evaluation of options for reduction of auxiliary consumption: case studies ...... 24 2.7 Evaluation of benefits for recommended options ...... 31 2.8 Emission reduction from reduction in auxiliary consumption ...... 32 2.9 Other plant related technical options for energy savings ...... 33

3 A systems approach to estimate savings from reduction in auxiliary consumption ...... 41 3.1 Introduction ...... 41 3.2 The NATGRDD model: an overview ...... 42 3.3 Analysis and scenarios ...... 43

4 Reduction of transmission and distribution losses ...... 45 4.1 Introduction ...... 45 4.2 Assessment of losses ...... 46 4.3 Identification of losses ...... 46 4.4 Measures for reduction of technical losses ...... 47 4.5 Measures for reduction of commercial/non-technical losses ...... 50 4.6 Measures taken by MSEB to reduce T&D losses ...... 50 4.7 MSEB: A study of losses ...... 51

IX Part III: Demand side management options

5 DSM options for HT industries in Maharashtra ...... 56 5.1 Introduction ...... 56 5.2 Consumption pattern in HT industries ...... 56 5.3 DSM options ...... 58 5.4 Formulation of DSM programmes ...... 58 5.5 COMPASS model...... 59 5.6 DSM option analysis ...... 60 5.7 Synthesis of programmes: 5-year DSM plan ...... 76 5.8 Impact on peak demand ...... 78 5.9 Impact of DSM plan on environment ...... 78

Part IV: Synthesis

6 Barriers in implementation, institutional and financial mechanisms ...... 80 6.1 Identification of barriers ...... 80 6.2 Recommended measures ...... 82 6.3 Recommendations for future work and role of various agencies ...... 84

References ...... 86

x Executive summary

Environmentally sound energy efficient strategies: a case study of power sector in India

India ’s energy consumption is increasing and it is likely to grow for quite some time as efforts to provide better living standards to her population are made. Thus, during the last decade, India ’s energy consumption more than doubled from 91 million tonnes of oil equivalent (mtoe) in 1980-81 to 189 mtoe in 1991, reaching 219 mtoe in 1994-95. Most of the increased energy consumption has been contributed by coal and oil, the fuels that are also associated with emissions of greenhouse (GHG) gases. As a signatory to the Framework Convention on Climate Change that was adopted at Rio by the international community, India needs to pursue environmentally sound energy development. Since fossil fuel use contributes the largest share of GHG emissions in the atmosphere, efficient production and use of energy j can reduce emissions and put India on a low energy intensive growth path, and thus benefit g the environment most in the long term. Equally of concern are the health effects associated with fossil fuel use, and soil and water pollution due to coal based power plants. Thus, one of the best ways to improve quality of life and reduce environmental damage is also by increasing energy efficiency.

Coal is a major source of energy in India, providing more than 60% of the commercial energy ) requirements. Coal is also most polluting fuel in terms of GHG emissions. Considering India ’s energy resources, coal may continue to provide a large part of energy requirements in the future too. Coal is mainly used for generating electricity. Therefore, efficient measures for generation, transmission and end use of electricity can help in reducing the environmental pollution, leading to environmentally sound development. The report highlights some such important measures; reduction in auxiliary consumption (ie. the electricity consumed by generating units in the process of generation), reduction in transmission and distribution losses, and application of demand side management (DSM) options for high tension industries. A glance at India ’s power sector indicates considerable scope for improvement in these areas; auxiliary consumption in various thermal power stations in the country varied between 8 to 14% in 1994-95, transmission and distribution losses between 16.4 and 25.5% in major power consuming states (with an average of 21% at all-India level). DSM options, that have already made impact in some of the developed countries, are yet to make a headway in India. .!

The study was conducted in two phases. Maharashtra State Electricity Board (MSEB), the largest utility in Maharashtra was chosen for the detailed study in the first phase. For the study of auxiliary consumption, two typical plants of the MSEB were selected. The transmission losses were studied for the MSEB system based on a snap-shot picture of the i system. For the DSM part, energy saving potential in HT industries in Maharashtra was explored based on a survey of HT industries.

In the second phase of the study, two more plants outside Maharashtra were also studied to get better insight into diverse causes for the different levels of auxiliary consumption and

XI estimate potential savings. All India potential for savings through reduction in auxiliary consumption was also estimated in this phase.

Auxiliary consumption

The consumption of electricity by power plant auxiliaries depends on factors such as unit size, level of technology, plant load factor, coal quality etc. The largest share of installed capacity in India (about 48% in 1995, accounting for 25,600 MW approx.) was from 200/210 MW units, most of which were installed in the late seventies, and eighties. The auxiliary consumption in these plants varied between 8 to 14%. A majority of these plants are yet not due for renovation, but available technology for power plant auxiliaries has considerably improved since their installation, indicating substantial scope for reduction in power consumption in these plants through up-gradation of auxiliaries. The case study was therefore focused on 210 MW power plants.

Auxiliary equipment upgradation: High auxiliary consumption in power plants can be due to the factors outside control of an individual plant; for example, coal shortages and poor coal quality, grid requirements (backing down, reactive generation requirements) etc. However, there are several technological and other plant related factors that can be addressed to reduce auxiliary consumption. Replacement of existing drives for ID fans and BFPs by variable speed drives, utilization of flash steam from continuous blow down and waste steam LSHS tank heating to provide air conditioning in the plant through vapour absorption system, cooling tower system improvements (for example, through a system to apply 24 volts on motor windings to prevent ingress of moisture in Nasik TPS), retrofit for ash handling system, and pulse energization of ESPs were evaluated for the cage study plants. Overall energy and C02 savings, payback periods and cost of C02 reductions from various options are given in Tables 1 and 2. The reduction in auxiliary consumption as a percentage of electricity generation for these units is between 1.53% and 2.2%, respectively. If an average auxiliary consumption reduction of 19 million units (MU) is considered for 80 units of 210 MW (about 70% of the total 120 units), energy savings work out to 1520 MU and C02 emissions savings are approximately 1.5 million tonnes per annum.

Other measures: Improvement in the power factor of auxiliaries, proper sizing of auxiliaries, and measures such as sliding pressure operation of units (as against BFP discharge throttling to keep turbine inlet pressure constant), instrumentation for auto air-load control to run the unit with optimum excess air, reliable flame monitors etc. can be selectively studied for individual power plants. Coal beneficiation to improve coal quality and turbine uprating (from 210 MW to 235 MW, already a proven upgradation technique) are other promising alternatives that offer quantum jump in efficiency of power production.

All-India level energy savings: NATGRID model developed at IGIDR was used to quantify possible cost savings resulting from energy savings through reduction in auxiliary consumption at all-India level. The model considered 19 electric utilities with 210 generating units, 90 inter-utility transmission lines, 23 major coal-fields and 97 power station to coal field linkages to minimise the total system cost. The results are given in Table 3.

Xll

14%

(Years),

1.9 3.0 2.6 4.7 4.6 3.3 2.0 2.9 2.2 0.5 13.8 Period

Economical

Not Discounted Payback

Savings

1.51 8.135 2.75 11.25 11.75 39.113 24.147 34.2875 63.8 99.3275 23.2075 103.21 (Rs.Million) Annual

unit.

one

Saving

only

has Energy

1.1 9.7 3.254 9.283 0.6 4.5 4.7 15.7 13.715 41.3 25.5 39.731. that

(MU®) Potential

Panipat,

Annual except

approx).

35 stations

options Cost

Rs.

1 2.9 = 90 90 30 80 90 60 power 180 180 120 180

Capital (Rs.Million)* emissions. all US$

(1 for

recommended reduces

it of Rupees.

210

since of

Rs. KSTPS PNTPS FTPS KSTPS NTPS FTPS NTPS PNTPS

! benefits units

3 System of

Improvement Improvement justified,

units;

for

are

Design study

million

Handling

Utilization

however,

Fan = data

Energization is, Evaluation

Ash

ID BFP

Tower It IGIDR MU The

1. Steam

for for Field

Options VSD Cooling (NTPS) Waste ESP VSD Alternate Table @ * Source: Note:

Xlll 30.4 163 876 303 212 560 PNTPS (Rs./Ton)

61.4 305.1 333.3 442 KSTPS 1796.4 1146.1 Reduction

>2 55.6 CC 302 569 430.6 FTPS

1040.3 1626 of

- Cost 383.5 329.5 290.7 NTPS 1778 1134.8 10 18 52 71 75 146 369 Tons)

PNTPS 000 ’ (

8.7 16.3 66.8 69.8 203.6 590 955.2 KSTPS Reduction

9.6 18 73.8 76.9 FTPS 158 418 754.3 Emission

2 - 8.8 67.5 70.5 savings NTPS C0 234.7 619.3

1000.8 2 CO

8.8 16.5 48.8 67.5 70.5 for 139.3 351.4 PNTPS MU options 8.8

16.5 67.5 70.5 205.7 596 965 KSTPS Savings,

8.8 potential 16.5

67.5 70.5 FTPS 145 691.3 383 Energy different 8.8

67.5 70.5 NTPS 234.7 619.3 of existing 1000.8 Already

Design

Study

Fan

System Ash ID BFP Contributions

Tower

Steam IGIDR

2. for for

Field

Utilization Handling Cooling Waste ESP VSD VSD Improvement Total Energization Alternate Table Source:

XIV Table 3. Reduction of auxiliary consumption considering national grid operation

Parameters Auxiliary Consumption

Actual Restricted 10% Restricted 8%

Total System Operating Cost (Million Rs.) 46,215 45,101 45,188 Unmet Energy (MU) 15,811 15,010 14,352 Total Generation (MU) 45,757 45,788 46,778 Total Auxiliary Consumption (MU) 3,246 3,017 2,586 Coal Based Generation (MU) 30,104 30,095 29,906 Total Coal Supplied (’000 Tons) 22,101 22,095 21,965 Average Generation Cost (Rs./kWh) 1.01 0.985 0.966 Average Thermal Units Auxiliary Consumption (%) 10.8 10.02 8.6 Annual C02 Reduction (’000 Tons) - 589 1239 Rate of Emission (Tons/kWh) 0.7239 0.723 0.70

Source: IGIDR Study

The C02 emission savings range from 0.7 million tons to 1.5 million tons per year. Since decrease in unmet demand in this exercise also comes from reduction in auxiliary consumption, same has also been considered while calculating savings. Over the life time of the power plants, the savings could be as large as 23 million tonnes.

Reduction in transmission and distribution losses

Transmission and distribution (T&D) losses of major states in India varied from 16.4% to 25.8% in 1992-93 with an all-India average of 21.8%. Although losses in developed countries are very low compared to this, considering its special characteristics, expert committees have suggested an upper limit of 15.5% for Indian power system. MSEB system is relatively efficient with losses at 16.4%, but losses have varied from a low of 14.3% in 1987-88 to 18.3% in 1990-91. A break up of the typical losses in MSEB system indicated that although transmission losses are within the prescribed norms, distribution losses are higher. The T&D losses can be technical losses such as transformer and feeder losses and non-technical losses (also known as commercial losses), that are mainly due to pilferage and faulty meters.

Distribution system study requires a field study to measure losses at different locations in the network. An experimental study was outside the scope of present study. However, a MSEB study indicated overloading of 8000 distribution transformers in the system and a high reactive load (with power factor as low as 0.6) resulting in high losses. The measures initiated by MSEB to reduce losses include provision of additional transformers in case of overloaded areas, requirement of capacitors for LT consumers at their premises, leasing scheme for LT capacitors for transformers for agricultural consumers, and upgrading transmission voltage, wherever possible. Steps have also been initiated to check commercial losses. There are several measures that can be taken to reduce distribution losses depending on the causes that are identified based on a field experiment. Short term measures include reconductoring, installation of capacitors, reconfiguration of the network, upgradation to high voltage transmission etc. In the long term, system can be optimized through a detailed system study.

xv Transmission losses in the high voltage network were studied for the MSEB system based on a snapshot picture of a typical peak hour. The analysis indicated scope for improvement in losses even for HT transmission. At some buses in the system, reactive power compensation was observed to be inadequate resulting in voltage drop (and hence losses). Thus, increased reactive compensation can reduce transmission losses further. The results are summarised in Table 4.

Table 4. MSEB HT transmission system losses

Type of Bus Actual Voltage Range Power Factor Remarks

400 kV 378 kV - 401 kV - Out of 9 buses, 3 had none and 2 had inadequate compensation.

220 kV 211 kV - 225 kV 0.77 - 0.79 Seven buses were with PF and voltage in this range. In addition to this, two buses were with low voltage, 206 and 204 KV.

132 kV 121 kV - 123 kV 0.79 - 0.81 Eight buses were with PF and voltage in this range. In addition, three buses had low voltage, 121 to 122 KV.

100 kV 96 kV - 99 kV 0.69 - 0.78 There were four buses with PF in this range.

Demand side management (DSM) options

The DSM study is based on an earlier comprehensive study carried out at IGIDR, that included a survey of HT industries. DSM offers several advantages such as reduction in electricity generation requirements on account of energy savings, short gestation period of 1 to 2 years for DSM measures as against 4 years and more for power plants, reduced burden on infrastructure such as transport (as a result of reduced fuel requirements) etc.

The HT industries in Maharashtra consumed 31 % of the electricity in 1992-93 and accounted for 38% of peak demand. Motors, melting, electrical heating, compressed air, air conditioning and lighting were major end-users of electricity. DSM options considered were energy efficient motors, variable speed drives, good house keeping practices, vapour absorption refrigeration systems (VARs), improved electric arc furnaces (EAFs), efficient lighting systems (replacement of 250 W high pressure mercury vapour lamps by 150 W high pressure sodium vapour lamps, replacement of Incandescent by Compact Fluorescent Lamps (CFLs), and replacement of magnetic ballasts by electronic ballasts), high efficiency fans and pumps, improvement in power factor (PF), industrial Cogeneration (COGEN), and time of day tariff (TOD). These options were evaluated using COMPASS software. The payback period for these options varied between 0.5 to 2.4 years with an active DSM programme, and between 0.6 to 4 years without a DSM programme. DSM programme is required to accelerate rate of adoption and diffusion since typical consumer discount rates to evaluate an option are very high; 25% and above as against utility discount rate of 14%. A five year DSM plan (1994-98) was worked out (Table 5). It can be seen from Table 5 that with all the identified options, demand savings of 760 MW and energy savings of 8590 million units are possible in a five

xvi year period. The cost of saved demand for the utility is Rs. 4500/kW, and overall cost (including DSM participants costs) is Rs. 15900/kW. The peak demand is expected to flatten gradually by the above order over a five year period.

Table 5. Five-year DSM plan for Maharashtra - summary of results

DSM Option Demand Energy Savings Programme Utility CSE Rs/kWh Savings in 1998 cost Total (MW) (MU) (Rs. million) Rs/kW Rs/kWh resource

TOD 160 - 376 1700 - 2100 EAF 26 356 69 2000 0.20 7500 CFL 1.5 17.8 4.5 2900 0.61 6300 GHK 80 906.4 415 3800 0.86 11900 HPSV 1.6 29.1 13 6500 -0.1 9700 EEM 14.3 169.3 189 9000 0.63 17600 VSD 54.1 1260.7 196 10200 1.05 41100 VARS 16.2 301.3 219 10600 0.64 28000 ELB 3.5 35.7 63 12400 1.00 24300 PUMPFAN 23.3 304.4 278 8500 0.77 28000 PF 58.2 0 78.1 800 3200 Total 436.7 3380.7 1900.6 4300 0.82 12700 COGEN 323 5211.6 2328 4800 0.76 19100 Grand Total 759.7 8592.3 4228.6 4500 0.78 15900

The impact on environment is through reduced emissions of C02, and other local pollutants like S02 and NOx . More than 9 million tonnes of C02 and 27 and 43 thousands of S02 and N02 respectively is expected to be emitted less over the five year period.

Barriers in implementations

Institutional barriers: Currently, there is no institutional mechanism in the utilities to systematically take up issues related to upgradation of equipment in power plants, T&D lines, and DSM formulation and implementation. The thrust of the current set up in the utility is on expansion rather than consolidation and modernization of existing stock. As a result, returns are poor from the existing plant and equipment. Due to lack of an institutional set up, other barriers such as technical, communicational also exist that hamper implementation of upgradation programmes in these areas. Technological barrier may also exist due to lack of exposure and training of the plant personnel.

Institutional set-ups are therefore needed at plant and overall utility level to take up upgradation programmes in these areas. Outside experts can be associated with such set-ups (for example from consulting firms, power plant manufacturers, universities etc.) to synergise the expertise. In case of DSM, innovative approaches such as energy service companies (ESCOs), consortium approach (consisting of utility, industry associations, financial organisations and relevant governmental agencies) need to be explored.

XVII Financial barriers: Currently, there is no appropriate financial mechanism to carry out upgradation programmes, except for complete plant renovation. Therefore, even if upgradation plans were to be systematically formulated, non-availability of funds may be a problem. One of the major reason for this is current pricing policies for the power, that make the utilities financially dependent on government. Further, the current policies are neither conducive to conservation nor to build up a healthy power sector that may be capable of raising its financial requirements. DSM programmes need explicit funding mechanism that also does not exist. Besides a funding mechanism, launching of DSM programmes would first require a demonstration through a pilot project. However, the pilot project can be funded by some of the existing energy funding programmes of IDBI and ICICI.

Restructuring and reforming power sector policies is vital to success of conservation programmes. International agencies such as World Bank, ADB, GEF etc. can also be approached for relevant programmes in these areas. ESCOs can become viable with sound power pricing policies, and raise money from the market.

Recommendations for future work and role of various agencies

Based on the foregoing discussion on the barriers to DSM and the institutional and financial mechanisms needed to overcome them, following steps have been identified for the next phase of work.

(i) Action by MSEB

(a) Formation of an expert group in MSEB at the apex level (in the corporate office/planning department), responsible for drawing up short term and long term measures for technological upgradation for plants and T&D lines, and conservation programmes including DSM. Experts need to be drawn from various plants and T&D zones/stations and outside organizations. For example, depending on area of expertise, experts from other utilities, NTPC, manufacturing organizations like BHEL, other industries, institutes/universities, and governmental agencies like EMC can be associated with the group.

(b) Formation of a task force in each plant and T&D zone to formulate and execute the plan for the plant or T&D zone/station, based on the recommendations of the expert group.

(c) Formation of a consortium consisting of representatives from MSEB, industry (equipment manufacturers), associations like CII, governmental agencies (like EMC) and a research institute/university working in this area, to initiate a pilot project for DSM.

(d) Commissioning a study on reforms required in pricing policies and interacting with the state government for carrying out the reforms.

xvm (ii) Action by the State Government

(a) Providing the necessary information, policy guidelines and support for working out the pricing reforms by MSEB.

(b) Assistance in getting the recommended pricing reforms implemented, if necessary through legislation.

(d) Introduction of more autonomy and accountability through an MOU with the MSEB and if necessary, initiating steps to convert the board into a company for this purpose.

These measures are expected to not only tap the conservation potential that this study indicates, but go a long way in improving the overall working of the utility.

xix XX 1 Introduction

Environmental protection and ecological balance are essential to ensure that a country ’s economic development is sustainable in the long run. Land abuse, water and air pollution, soil erosion, deforestation, loss of biological diversity, siltation of rivers, and other problems associated with resource (fuel) extraction and deployment pose a threat to ecological security and human health. Over the past decade, it has been recognized by scientists and policy makers worldwide that increasing atmospheric concentrations of greenhouse gases originating from human activities, particularly the burning of fossil fuels, may lead to catastrophic environmental impacts due to global warming/climate change.

As a developing economy, India ’s consumption of energy is increasing and is likely to grow, given the attempt to provide a better standard of living to her population. Thus, during the last decade, India ’s energy consumption more than doubled - from 91 million tons of oil equivalent (mtoe) in 1980-81 to 189 mtoe in 1990-91; it was 219 mtoe during 1994-95 (CMIE, 1995). Most of the increased energy consumption has come from coal and oil, that are also associated with emissions of carbon dioxide (C02), oxides of sulphur (SOx) and nitrogen (NOx) and particulates. C02 is a greenhouse gas (GHG) and limiting its high level of global emissions is a major issue in the debate on global warming and climate change. Table 1.1 gives the data on primary energy supply in India for selected years during the last decade.

Table 1.1. Supply of primary sources of commercial energy (Mtoe)

Coal Oil Natural Gas Hydro Nuclear Total supply of energy

1980-81 55.97 26.76 2.02 3.88 0.25 91.38 1985-86 76.76 44.78 6.97 4.24 0.42 137.12 1989-90 100.73 53.58 14.55 5.17 0.39 180.61 1990-91 106.63 53.73 15.42 5.96 0.52 189.17 1991-92 115.29 54.37 15.98 6.05 0.46 199.97 1992-93 120.06 56.37 15.98 5.82 0.46 206.83 1993-94 124.02 57.52 15.98 5.86 0.46 212.72 1994-95 128.52 58.00 15.98 6.88 0.46 219.24

Source: CMIE, 1995

Economic development has strong linkages with energy, since higher growth requires higher energy inputs. However, the amount of extra energy required for growth is also a function of the efficiency with which energy is used. A low energy intensive growth path (as in Japan ’s economy, for example) would require less incremental energy for growth. An economy adopting a low energy intensive path would require a lesser amount of energy for a particular level of GDP. It is therefore important to modify growth paths of developing economies in order to reduce pollution and future GHG emissions.

1 1 The energy sector accounts for 25 to 30 per cent of the planned investment in India. Within every sector, a major part of the increased energy requirements are met by the power sector. Electricity consumption has been growing at a rate of 8 to 10 per cent per year in India and the power sector accounts for more than 60 per cent of the investments in the energy sector. The planned investment in the power sector is about Rupees (Rs.; 1 US$ = Rs. 35 approx.) 800 billion in the Eighth Plan (1992-97), besides substantial investment proposals received from the private sector. Thermal power dominates the installed power capacity of the power sector in India (about 72 per cent of the total 81,164 MW in 1995) and also has the highest growth rate.

Most of the thermal power is generated from coal, one of the most polluting fuels. In fact, coal is a major energy source in India as well and provides more than 60 per cent of the country ’s commercial energy requirements. Considering India ’s energy resources, coal may continue to provide more than 60 per cent of her energy needs in the future too. On the other hand, as a party to the Earth Summit at Rio in 1992, India has a commitment to adopt strategies and take all possible actions that help in reduction of emission of GHGs. Besides the issue of GHG emissions, several cities in India are facing serious environmental problems due to local pollutants. Environmentally Sound Energy Technologies (ESETs) require less primary energy for the same amount of end-use energy. This is achieved through efficiency improvements in energy production and use. Therefore, they could help in reducing energy consumption and associated emissions without retarding the economic growth or output and are thus potential alternatives to reduce GHG emissions. ESETs not only address global environmental issues due to reduction in GHG emissions, but also local environmental issues, since emissions of pollutants like NOx , SOx , etc. are also reduced.

In a study carried out at IGIDR, on the impact of global warming due to fossil fuel use, (Parikh and Gokarn, 1993) it has been shown that the highest emissions in India are due to the power sector (42 per cent), followed by iron and steel (9.5 per cent), road and air transport, coal tar and so on. However, the construction sector accounts for the highest share, when direct and indirect emissions are considered. So far, energy policy in India has emphasized savings of oil and electricity. However, taking into account the concerns of climate change, India may have to shift its policy to include reduction in the use of coal as well, even though it might involve a net loss in savings. For example, if 250 PJ of energy (1 PJ = 106 GJ) is saved from coal, it would mean a saving of Rs. 2,706 million only. If the same energy is saved from oil conservation it could save Rs. 7,710 million. Thus, conservation of energy from coal will involve a loss in savings of Rs. 5,004 million when compared to savings that can be made by oil conservation. This can be interpreted as an incremental cost to the Indian economy for following a coal conservation policy.

1.1 Environmental impacts of energy related activities in India: a review of studies

The Asian Development Bank (ADB) commissioned a study (Anon, 1993) to bring out the impacts of climate change and India ’s options to cope with them. The study compares the GHG emission estimates made for India by various experts. Sectoral emissions for agriculture, energy and transport are also discussed. A major part of the GHG emissions in India are from

2 production and energy use activities. The study pointed out that climate change may affect biomass productivity and forest fires may occur frequently. It may also have adverse impacts on biodiversity. Potential abatement measures indicated in the study are increased energy utilization efficiency, deployment of renewable energy technologies and afforestation. Estimates of GHG emissions by CSIR (under the national programme for emission estimation) and other agencies like OAK Ridge and US EPA, as well as energy sector policy issues and environmental issues have been discussed in the study. The study recommends that, considering projections of increased commercial energy supplies in India, efforts are required to reduce future rates of CO2 emissions.

Since energy use is a major source of GHG emissions, it is recognized that efforts to save energy are required in all countries. Parikh and Gokarn (1993) have examined the energy flow in the Indian economy considering a 60 sector input-output model. They argue that it would be more expensive for India to save energy from coal (which is now advocated at international levels) than from oil. India has pursued the policy of saving oil, because of her dependence on oil imports. If priority is given to GHG emissions reduction, India will have to forego substantial savings and also change her sectoral priority in favour of saving coal. The authors also show that the largest contribution to direct emissions came from the power sector while direct and indirect emissions by final demand are the largest in the construction sector. Therefore, these two sectors need in-depth analysis to identify ways to reduce emissions without compromising developmental goals.

Emissions of CO2 and other pollutants can also be reduced by improvements in the power system. Chattopadhyay and Parikh (1993) demonstrate that reduction in emissions can be achieved at a substantially lower cost with integrated optimal operation of the regional grids. Other options include gas based generation and thermal efficiency improvements of plants.

1.2 A brief review of the performance of the Indian power sector

The installed capacity of generation in India was 81,164 MW as on March 1995; this comprised 20,829 MW of hydel, 58,110 MW of thermal and 2,225 MW of nuclear units. During 1994-95, there was an increase in actual power generation of 8.5 per cent over the previous year. This was mainly due to a sharp growth of 17.3 per cent in hydro generation during the year, helped by a healthy south-west monsoon. However, thermal generation was less than the target, reportedly due to shortage and poor quality of coal, unscheduled forced outages and paucity of funds with the State Electricity Boards (SEBs). With the increasing demand situation and additions in generating capacity, power generation will increase in the future, and will lead to further environmental degradation. Table 1.2 highlights some of the key parameters of the Indian power performance during 1994-95.

3 Table 1.2. National powerscene at a glance

Parameters North East South West North-East All-India Installed Capacity (MW) 23,820 12,302 19,459 24,301 1,282 81,164

8th plan Capacity Added till 3,629 3,149 2,225 3,452 221 12,675 March 1995 (MW)

Balance from targeted 6,198 3,984 2,204 4,239 1,238 17,863 (1992-97)

Generation 102,766 35,408 92,026 116,421 2,337 351,025

Thermal Plant Load Factor 59 44 69 64 27 60 Per Capita Consumption (kWh) 282 158 308 405 89 282

Source: CMIE, 1995

The financial performance of the SEBs has been below par. The commercial losses of all the SEBs put together were Rs. 41,170 million by March 1992; this increased to Rs. 43,580 million by March 1993, to Rs. 49,950 million by March 1994 and is estimated to have reached Rs. 63,320 million by March 1995. A large portion of these losses is accounted for by the sale of power to agriculture and domestic consumers at a cost lower than the cost of production. Due to their poor financial conditions, the SEBs are unable to make further investments for environmental improvement.

A feature of the Indian power scene that causes concern is the decreasing share of hydro power as compared to thermal power, for this means increasing air pollution. The share of hydro capacity was 42 per cent of the total capacity in 1980 but only 27 per cent as on March 1994. The central government has initiated actions for evolving ways and means to increase the share of hydro power in the total installed capacity to 40 per cent by the year 2002. The Central Electricity Authority (CEA) has estimated India ’s hydro energy potential at 84,044 MW with 60 per cent load factor, which would mean an annual energy generation of 600 billion units. This is, however, unevenly distributed, with three-fourths of the potential situated in the northern and north-eastern regions. The Brahmaputra basin alone accounts for 41 per cent of the total potential, of which only 1 per cent has been exploited. The main reasons for low percentage of development over the potential are: (i) The bulk of the potential lies in the states which lack the resources to develop them; (ii) Inter-state disputes and sharing of river waters; (iii) Problems in land acquisition, afforestation and rehabilitation of project affected persons.

An important development is the government decision to encourage private - both domestic and foreign - investment in generation. Till July 1995, 243 project proposals for adding a total capacity of 90,368 MW at a total cost of Rs. 3,354 billion have been received. The entry of private plants raises a new set of issues concerning procedures and terms of contract and regulation.

4 1.2.1 Transmission and distribution

The targets for new transmission lines during 1993-94 were fixed at 4,606 circuit-km consisting of 1,506 circuit-km of 400 kV and 3,100 circuit-km of 220 kV lines. As on November 1994, 995 circuit-km of 400 kV and 1,757 circuit-km of 220 kV lines had been completed.

All-India transmission and distribution (T&D) losses stood at 22 per cent during 1994-95. The much higher loss figure reflects considerable theft of power and inefficiency. The country lost an estimated revenue of Rs. 50,000 million due to T&D losses. Investments in the T&D systems have been much lower than the prescribed 40 per cent allocation of the total power sector outlay (it was 24.9 per cent during 1993-94), which partly accounts for the high T&D losses. It can be estimated that a one percentage point reduction in overall T&D losses would be equivalent to an addition of 800 MW of capacity.

Most of the losses occur at the distribution level (i.e 11 kV and below), where losses arising from pilferage of energy, inaccurate meter readings, defective meters etc. are also considerable. Though pilferage may not amount to a net economic loss to the country, the loss of revenue to the SEBs is significant; their ability to serve paying customers is also affected adversely. Deterioration in the efficiency of the T&D system due to overloading of transformers, transmission lines, distribution network and increased rural electrification covering thinly spread consumers, have contributed to high T&D losses.

1.2.2 Consumption

In developing countries, reducing per capita electricity consumption to preserve the environment is not an option because consumption levels are very low. However, the efficiency with which electric power is used can be increased. In the fifties, per capita consumption of power was 16 kWh only. It crossed the 100 kWh mark in 1975-76 and rose to 200 kWh per capita in 1987-88. During 1992-93 the per capita consumption was 283 kWh.

The agricultural sector accounted for 30 per cent of power generation during 1994. This is because of the growing use of electric pumpsets in this sector. 10.5 million pumpsets had been energized by 1994-95. Domestic consumption accounted for 18 per cent of the generation. However, the share of industrial consumption has been declining from about 60 per cent in 1979-80 to 40 per cent in 1994-95. This may only partly be attributed to increasing reliance on captive power plants.

During 1994-95, the target for village electrification was 3,708 villages, against which 1,317 villages were electrified up to December 1994. About 85 per cent of the villages in India have been electrified by 1994.

1.2.3 Private sector participation

In order to meet the growing demand and in view of the slippages in capacity addition from targets and unavailability of investable funds, the government has invited entry of private parties to the power sector. There are 243 private sector projects pending till July 1995. If all of them materialize, the total capacity addition from these projects would be 90,368 MW,

5 involving an investment of Rs. 3,354 billion. Of these 43 are foreign companies and involve 33,554 MW costing Rs. 1,292 billion. Memoranda of understanding have been signed for 123 projects with a capacity addition of 55,609 MW at a cost of Rs. 2,096 billion (CMIE, 1995).

The central government on its part has decided to accord some of these projects a counter guarantee against the commitment of state governments on payment for energy supply. It has been decided that all private companies would be allowed a debt-equity ratio up to 4:1. Fixed cost including 16 per cent return on equity can be recovered at 68.5 per cent Plant Load Factor (PLF). Incentives are prescribed beyond this PLF in the form of additional Rate of Return (ROE) (upto 0.7 per cent) for each 1 per cent rise in PLF. The customs duty for import of power equipment has been reduced to 20 per cent. A 5-year tax holiday has also been allowed in respect of profits and gains of new undertakings for either generation or generation and distribution of power. Excise duty on capital goods and instruments in the power sector has been reduced to a uniform rate of 5 per cent. Foreign investors are also allowed to repatriate dividends entirely in dollar terms, with full protection against exchange rate fluctuations.

1.2.4 Demand side management

The Eighth Plan provided, for the first time, a capital outlay of Rs. 10,000 million for energy efficiency measures. The targeted energy savings are 5,000 MW and 6 Mt in the power and petroleum sectors respectively. A target of 2,250 MW of demand savings in the industrial, commercial, agricultural and domestic sectors has been set for the Eighth Plan. The National Energy Efficiency Programme during the Eighth Plan includes a policy package comprising financial arrangements including creation of a revolving fund, technical assistance, technology development, selective legislation and developing institutional capabilities. However, the targets and the capital outlay have been fixed arbitrarily with no realistic measures specified to achieve them.

Demand side management (DSM) measures include accelerated measures for energy efficiency, peak load shifting and other measures. DSM is therefore more than energy efficiency. DSM does not, by any means, eliminate the need for more power in the future. However, considering the expected high growth of power requirements, DSM reduces the need for new capacity significantly.

An integrated framework for analysis of DSM options together with electric utility planning is called for (Chattopadhyay, Banerjee, Parikh, 1994), in order to evaluate all the benefits associated with DSM programmes.

Several policy changes need to be effected to encourage energy efficiency such as abolition of customs duty for energy saving/and energy audit equipment not available in India, and waiver of excise and sales tax levies on energy saving devices.

6 Demand Side Management for Energy Conservation: Not by Exhortations Alone

According to IGIDR estimates (Parikh, Reddy and Banerjee, 1994) savings of about 400 MW can be achieved during the next five years in Maharashtra; while over the next 20 years, technological and managerial options (including peak load pricing) by the industrial sector alone can reduce the need for additional capacity up to 3,000 MW. On an all-India basis, this works out to about 15,000 MW. This is at the average cost of Rs. 3,300/kW: one-tenth of that required for new capacity, ranging around Rs 35,000/kW at present. These saved (or avoided) MW are often termed Megawatts. India ’s policy for power should be such that Megawatts and Megawatts are provided a level playing field. Soft loans, guarantees, and other benefits, if given to Megawatts generation, should be first available for Megawatts, since they have the additional advantage of reducing the need for fuel, land and water as well as lessening pollution. A cost sharing approach would be beneficial, by which substantial costs could be met by industries and only incremental costs could come from DSM programmes which also include demonstration and awareness programmes and other extension services. The agricultural sector receives power at such subsidized rates that farmers do not purchase efficient motors since their electricity bill savings will be negligible. Either non-market instruments other than DSM will be required to address this sector or else market prices for power will have to be charged before the farmers agree to pay more for energy efficient motors. Why is it at all necessary to have DSM programmes, if the measures are so cheap? Because customers do not compare their costs with that of building new power plants but with other investment opportunities for themselves which may give a higher rate of returns. Their borrowing rates can range from 18 per cent to 25 per cent whereas utilities (or social discount rates) pay lower rates. Customers will not purchase more efficient equipment, if these are costly. Then more power plants will be required to add more industrial customers to the utility. Electricity rates for industrial customers are already high. Often they cross-subsidize agriculture. Therefore, the instrument of electricity pricing cannot be overused for the industrial sector. Hence the need for DSM programmes. If, due to DSM, more industrial customers are added from the same power capacity, then when the costs go up, the rise is shared by a larger number of customers.

Box 1.1

1.2.5 Auxiliary consumption

A power plant consists of several pumps, motors and other equipments besides main equipments (boiler, turbine and generator). These are collectively known as power plant auxiliaries. Auxiliaries themselves consume power in the process of power production. Auxiliary consumption is expressed as a percentage of the power produced by the plant. It can vary in a thermal power plant depending on type of fuel, unit size, efficiency of auxiliaries, plant load factor (PLF) etc. PLF has significant impact on the auxiliary consumption. Low PLF increases percentage auxiliary consumption as the plant auxiliaries are optimized for full load operation in most of the power plants. The auxiliary consumption has been observed to vary from 5 to 14 percent in India. In a majority of cases, there is scope to reduce this below 10%.

7 Major Issues Involved in DSM Plan Implementation

Financial: Payback considerations Initial fundings Channelling costs and returns to beneficiaries

Techno-Economic: Limited ability of users in selecting and assessing suitability Need to reduce costs of some equipment Need to develop technologies or technology transfer

Institutional: Creating awareness Energy service companies Motivating consumers, utilities and equipment manufacturers Coordination with state and central bodies Formation of a nodal DSM agency Standards, penalties and statutory acts

Box 1.2

1.3 Environmentally sound technologies; supply side options

There are several options to improve supply side efficiencies and reduce emissions through application of environmentally sound technologies. These include new technologies as well as upgradation of existing technologies. The supply side management has benefit of addressing the issue at the point of supply, a relatively limited area where efforts can be concentrated and benefits derived without involvement of too many agencies. For example, in case of electricity supply, the utility concerned is the agency, and efforts can be concentrated in specific areas such as on generating equipments within the power plants, T&D lines in the grid and so on. Supply side options offer another benefit; expertize to understand and implement the technologies is available at the agency (utility) level. The options for the electricity sector can be briefly classified as follows:

• High efficiency systems. New technologies for the power plants offer quantum jumps in efficiency. Thus combined cycle plants using gas offer efficiency levels above 45%. Technologies such as Steam Injected Gas Turbines (STG), non-thermal cycles like Kalina Cycles, pressurized fluidized bed boilers, gas turbines using gasified coal etc. fall into this category.

• Non carbon fuels and renewables. This includes nuclear power, solar power and other renewables, and technologies such as fuel cells etc.

• Cogeneration and power from waste. These technologies are environmentally sound since the waste is currently burnt at very low efficiencies.

8 Supply side management options. These include plant renovation and uprating, upgradation of auxiliaries, system improvement through measures such as reduction of T&D losses, efficient grid operations, coal beneficiation etc.

1.4 Scope of the study

Technologies and energy use patterns vary between and within the different regions in India. Under the overall policy thrust of the central government, policies to effect changes in these are made at the state levels. Therefore, policies for implementation of any measure aimed at changes in technology and energy use pattern have to be prepared at the state level. In this study, options for reduction of emissions from thermal power stations with a view to identifying ESETs have been identified. ESETs can be adopted for generation (supply side) as well as use (demand side) of electricity. We look at options for both supply and demand sides in the study. On the supply side, the possibilities of reducing auxiliary consumption in thermal power plants by using efficient technologies have been examined at an all-India level. Auxiliaries consume a significant amount of power (between 8 and 14 per cent) in thermal plants in India and therefore, even a 1 per cent reduction implies substantial savings. Transmission and distribution is another area where losses are high in India. Possibilities for reduction of T&D losses have also been explored. On the demand side we look at options for the High Tension (HT) industries in Maharashtra, which are the major consumers of power in the state. End-of-the-pipe treatments like scrubbers to reduce sulphur pollution address the problem of environmental pollution only partially. Such measures can only improve the local

environment, leaving the CO2 problem untouched. The measures discussed in this study

consider CO2 as well as local pollutants.

The study consisted of two phases as follows:

1.4.1 Phase 1

(i) Case study of two power stations of Maharashtra State Electricity Board (MSEB) with a view to analyse auxiliary consumption.

(ii) Preliminary study of MSEB transmission system with the view to examine losses.

(iii) Potential for demand side management options in high tension industries in Maharashtra.

Thus, both supply and demand side were covered.

1.4.2 Phase 2

(i) Extension of the phase 1 auxiliary consumption study to include two more plants outside Maharashtra. This was done with the view to get better insight into auxiliary consumption pattern and potential for improvement. One plant of the National Thermal Power Corporation (a federal government owned utility) at Korba, and one that of Haryana State Electricity Board at Panipat were included in the study.

9 (ii) Estimation of potential for auxiliary consumption reduction at all India level. A systems approach has been developed to evaluate the savings from reduction in auxiliary consumption at an all-India level.

1.4.3 Case studies

(a) Maharashtra State Electricity Board

The state of Maharashtra is one of the most progressive states in India accounting for the largest share of industrial output and installed capacity for power in the country. Considering the importance of the power sector within the energy sector in India and the polluting nature of thermal power, it was decided to cover efficiency aspects of the power sector in the study. Within Maharashtra, the potential for application of ESETs has been studied at a utility level. The Maharashtra State Electricity Board (MSEB), which is a major state utility in Maharashtra, was chosen for the detailed study of potential. The study covers the following:

(i) Measures forreduction of auxiliary consumption in thermal power plants, an area that has not been studied systematically so far.

(ii) Reduction of transmission and distribution losses in the MSEB system. The purpose of the study was to throw light on the possible savings at the transmission and distribution level.

(iii) Identification of Demand Side Management options for High Tension industries in Maharashtra. This part of the study is based on an earlier comprehensive study on DSM carried out by IGIDR for MSEB.

(b) National Thermal Power Corporation (NTPC)

NTPC is a federal government utility engaged in generation of power and distribution in bulk to other state utilities. NTPC is considered efficiently managed utility. Therefore one power plant of NTPC (at Korba) was included in the study of auxiliary consumption.

HSEB is a relatively small utility in the northern region of India. One plant of HSEB at Panipat was included for study of auxiliary consumption.

10 2 Reduction of auxiliary consumption in thermal power stations

2.1 Introduction

The availability of a generating unit depends largely upon the operational reliability of auxiliaries and the ability in the auxiliary system to ensure continued availability of the unit in the event of failure of an auxiliary. In a thermal power station, auxiliaries are the consumption points. To the extent this consumption can be reduced, either by improving the design of the equipment or by optimizing auxiliary system design, generation efficiency can be increased and energy so saved be made available for sale.

A look at the progressive changes over the years in unit size and operating parameters of thermal generating sets indicates a steady development in unit sizes with a variety of technologies, upgradation of operating parameters, etc. The diversity of unit sizes in thermal power stations in India ranges from 30 MW to 500 MW of capacity. Most of the capacity addition done in the late seventies and mid-eighties have been in the 110 MW/210 MW unit capacity sizes which have completed about 50 per cent of their useful life. The present trend has been to add larger unit sizes of 250 MW/500 MW capacity. Alongside the growth in unit sizes, considerable technological innovations have also taken place in upgradation of auxiliary systems and improvement in designs of auxiliary equipment. These changes have increased the operational reliability and efficiency of the auxiliaries and of the power station in general.

2.2 Analysis of trends in auxiliary consumption in India

As described earlier, PLF has a significant bearing on a unit ’s auxiliary consumption. Auxiliaries in almost all the plants are optimized for full load operation. Therefore, at part loads, the auxiliary consumption does not reduce in proportion to the output, resulting in high auxiliary consumption. Figure 2.1 shows the state-wise average auxiliary consumption figures of thermal power stations with respect to the annual PLF. It can be seen that for those states whose auxiliary consumption is very high (Bihar and Durgapur Projects Ltd. (DPL), above 12 per cent) the annual PLF is as low as 30 per cent. For states with higher PLFs, the auxiliary consumption figures are lower. The National Thermal Power Corporation (NTPC) power plants have a significantly high annual PLF and the lowest auxiliary consumption. The SEB thermal plants also have moderately high auxiliary consumption figures on the average, with consumption in states like Uttar Pradesh (UP), West Bengal (WB), Madhya Pradesh (MP), Karnataka and Tamil Nadu (TN) being quite high.

One should, however, note that an over emphasis on thermal PLF can be a misleading indicator of power system efficiency. For example, if a good monsoon provides more water to generate electricity from hydel plants, it may be advisible to generate less from thermal plants. Thus, factors like the thermal unit backing down due to high hydro generation during the monsoon months, may lead to low thermal PLFs. Therefore, it is necessary to consider

11 15

14 □ BIHAR

12 □ DPL □ DVC

D NTPC (EAST) U.P □

D O CESC □ ORISSA □ □ B 8 □ □ MAH 3 O NTPC (SOUTH) HARYANA DELHI

7 □ NTPC (WEST)

NTPC (NORTH) 5 _!______I______L_ J_____ I_____ I_____ I_____ I_____ I_____ I___ ELl_____ I_ 20 30 40 50 60 70

Plant Load Factor —> CLUSTER-A CLUSTER-B W.B., MB., TAPS, KAPP, T.N., KARN AJ?., RAJASTHAN, GUJARAT, PUNJAB

Figure 2.1. State-wise auxiliary consumption pattern

Note: KAPP and TAPS are nuclear power plants. factors like backing down time and energy lost due to backing down, partial and forced outages, etc. while analyzing the PLF and associated trends in auxiliary consumption figures.

Figure 2.2 shows the unit-wise auxiliary consumption figures for all 210 MW units in India. The units have been graded into different categories based on their auxiliary consumption figures. As seen in Figure 2.2, grade F has the highest auxiliary consumption; above 12 per cent. Bokaro Thermal Power Station (TPS) units-5,6 and 7 are in this category. The grade E with auxiliary consumption between 11 to 12 per cent consists of 16 units spread over five thermal power stations. These are at Gandhinagar TPS, Satpura TPS, Kolaghat TPS, Parli TPS and Panipat TPS. The grades B, C and D, i.e. those with auxiliary consumption in the range of 8 to 11 per cent, account for the maximum number of generating units in India. Grade-D (10 to 11 per cent) has 22 units from 8 stations, Grade-C (9 to 10 per cent) has 31 units from 9 stations while Grade B (8 to 9 per cent) has 32 units from 12 thermal power stations. There are only four units of 210 MW capacity in grade A, Tuticorin-1,2,3 (7.56 per cent) and Badarpur-4 (7.95 per cent) where auxiliary consumption was less than 8 per cent.

12 Figure

Aux. Cons (K)

A: B: E: D: C: Figures F: 2.2. Bokaro GandhiNagar Vindyachal Neyveli

Unit-wise

12 13 10 11 within Tuticorin Farakka 5 (8.29), 7 8 9 5(11.4) (10.07) Obra 1-4

(8.62),

(9.6),

9-13 j □ D 7

brackets ____ Mettur

A (8.11), 1-3

auxiliary

Nasik 1,2,3 (12.2), Wanakbori

(10.48),

1-6 (10.05),

3,4

1-4

indicate (7.56), (9.0), 3-5 Tuticorin

Bokaro (11.28),

(8.3),

§ (8.72), Bhusawal

consumption

Chandrapur B Kahalgaon

1-6 Badarpur

auxiliary

Unchahaar

6,7 (9.65), 4,5 Satpura

Durgapur

_____ (12.7) Aux.

(8.2), 2,3 4

Cons S.Gandhi 1,2 D consumption

1-4 9

I 6-9 ______(7.95) (10.59), C

1-2 Vijaywada pattern

(9.14), Group-Wise 4

(10.07), (11.3),

(8.73), (8.43),

1,2 Tenughat Khaperkheda

Kolaghat

Ramagundam

Ukai figures

(9.7), Ropar L 1-5 D

(8.22),

3-5

Kota

1 1-6

1-6

(10.67),

(8.88),

percentages. (8.55), 1,2

4,5 (11.34),

Singrauli 1-3 11

(9.2),

(9.8),

Korba

(10.11), Kota Rayalseema

Raichur Parli

Korba

1-5

3 STBS

Anpara (10.74), 3-5 (8.23), O □ i

(W)

1-3 F (11.38),

1-3 1

(8.6), (9.29),

1-4 1-3 (8.86) Badarpur Koradi

(9.94)

(10.41), Panipat Bandel

Dadri

5-7 13

2.3 Unit capacity-wise share of generating capacity and energy generation in India

With the growth of the power sector, there have been significant changes on the technical front in terms of unit design, sizes and design of auxiliary units. With larger system operations and increasing demand, the trend has been towards larger unit sizes for economic reasons. Thus, the earlier units in the range below 100 MW gave way to 210 MW units and lately, unit sizes of 500 MW capacity are increasingly being introduced.

Table 2.1 provides a detailed state-wise break-up of the installed capacity for the three different groups of unit capacities, i.e. less than 100 MW, 200/ 210 MW and 500 MW. Also shown is the share of the installed capacity as a fraction of the total installed capacity and the share of that capacity group in total energy generation. The following inferences can be made from an analysis of Table 2.1:

(i) At all-India level, 210 MW capacity generating unit sizes accounted for the largest share (48.3 per cent of total capacity), generating 53 per cent of the total energy supply. 110 MW or smaller size units accounted for 33.3 per cent of total installed capacity for 27 per cent of the total generation while 500 MW units had a share of 18.4 per cent in installed capacity with a 20 per cent share in energy generation.

(ii) In the western region, the highest share in the total installed capacity is of 210 MW units (51.3 per cent), which account for 56.8 per cent of energy generation. The rest of the installed capacity in the region is from 500 MW (22.45 per cent) and 110 MW or lower capacity units (24.8 per cent).

(iii) The eastern region has the highest share in total installed capacity from 100 MW or smaller units (56.5 per cent). The region has no 500 MW units in the SEB plants, but 2x500 MW of capacity in NTPC’s Farakka Super Thermal Power Station (STPS). 31.8 per cent of the total capacity is of 210 MW unit sizes. In terms of energy generation, 52.4 per cent of the total generation in the eastern region was from 100 MW or smaller unit sizes and 41.5 per cent from 210 MW unit sizes. The 500 MW units however contributed less than 4 per cent of energy to the regional generation with 11.7 per cent share in capacity. It is evident that these units were operating at quite low PLFs.

(iv) The northern region has 44.4 per cent of installed capacity from 210 MW capacity units, 39.4 per cent of capacity from 110 MW or smaller capacity units and 16 per cent from 500 MW capacity units. The higher share of 110 MW and lower capacity units is due to the larger share of small hydro units in the region.

(v) 210 MW unit sizes have the largest share in the total installed capacity with a share of 64% in the southern region, 51.3 per cent in the western region and 44.4 per cent the northern region. In terms of share in energy generation too, the 210 MW units contribution was highest in all the regions. The 500 MW units also contributed a substantial part (about 20 per cent) of the total annual energy generation of the western, northern and southern regions.

14 Table

State 110/120 and smaller Units 200/210 MW Units 500 MW units

2.1. Capacity Energy Capacity Energy Capacity Energy

MU* MW % of total % of total MW % of total MU % of total MW % of total MU % of total Details Gujarat 1729 37.5 8272 34.4 2290 49.7 13230 55.1 588 12.76 2519 10.5 Maharashtra 1398 18.32 5152 14.5 3560 46.65 20584 57.8 2672 35.02 9854 27.7 - - - -

M.P. 852 27.1 3296 25.8 2290 72.9 9500 74.24 NTPC (W) 645 16.1 2244 8.9 1860 46.44 12752 50.9 1500 37.45 10,066 40.2 of

NPC (W) 320 59.3 1822 73.4 220 40.74 659 26.6 - - - - generating WESTERN 4944 24.8 20786 20.8 10220 51.3 56725 56.75 4760 23.9 22439 22.45

Bihar 1306 100.0 2782 100.0 _ - - _ DVC 1310 67.5 4372 65.4 630 32.5 2316 34.6 - - 100.0 1430 100.0 - - - - Orissa 460 W.B. 800 35.24 2549 28.5 1470 64.75 6396 71.5 - - unit DPL 390 100.0 902 100.0 - - - -

CESC 580 100.0 3491 100.0 - , - - sizes

NTPC (E) - - - - 630 38.65 4282 79.3 1000 61.35 1120 20.7

EASTERN 4846 56.5 15526 52.4 2730 31.8 12294 41.5 1000 11.7 1120 3.8 and

DESU 427 100.0 1765 100.0 . - - _

Haryana 605 74.2 2138 74.4 210 25.8 736 25.6 - - their Punjab 440 25.9 2737 30.9 1260 74.1 6111 69.1 - - Rajasthan 220 25.9 1228 27.1 630 74.1 3311 72.9 - -

U.P. 1821 46.1 4782 32.8 1630 41.3 7683 52.7 500 12.7 2102 14.4 contribution NPC (N) 100 13.5 152 10.0 640 86.5 1363 89.9 - - NTPC (N) 2167 32.7 9160 24.6 2470 37.2 14,259 38.3 2000 30.1 13,794 37.1 Others 300 100.0 830 100.0 - - - - NORTHERN 6080 39.4 22792 31.6 6840 44.4 33463 46.4 2500 16.2 15896 22.0

- - - -

Andhra 763 47.6 3476 38.6 840 52.4 5519 61.4 to ------Karnataka 630 100.0 3863 100.0 energy T.N. 450 19.2 2052 18.1 1890 80.8 9290 81.9 - - - - NLC 585 28.5 2832 34.0 1470 71.5 5489 65.9 - - NPC (S) - - - - 440 100.0 1979 100.0 - - - -

NTPC (S) - - - - 600 28.6 4062 28.0 1500 71.4 10433 72.0 generation SOUTHERN 1798 19.6 8360 17.1 5870 64.0 30202 61.6 1500 16.4 10433 21.3 ALL-INDIA 17668 33.3 67464 27.0 25660 48.3 132684 53.06 9760 18.4 49888 19.95

* MU refers to million units, where one unit = 1 kWh

Ui 2.4 Equipment-wise break-up of auxiliary consumption in thermal power station

The major electricity consuming equipment in a thermal power station can be broadly classified as follows:

(i) Boiler auxiliary system. Induced draft (ID) fan; Forced draft (FD) fan; Primary air (PA) fan; Coal mills; Electrostatic precipitators

(ii) Turbine auxiliary system. Boiler feed pump (BFP); Condensate extraction pump (CEP); Circulating water pump (CWP); Cooling tower pump (CTP); Cooling tower (CT) fan motors

(iii) Ash handling system. Low Pressure (LP) Pump; High Pressure (HP) Pump; Ash Slurry Pump; Seal Water Pump

(iv) Coal handling system. Various motors.

Equipment-wise consumption figures at three thermal power stations of capacity (3x210) 630 MW each, viz., Nasik Thermal Power Station (NTPS) Stage-II of MSEB, Parli Thermal Power Station (FTPS) Stage-II of MSEB and Korba Super Thermal Power Station (KSTPS) of NTPC, have been worked out for the peak loading condition (Table 2.2). The break-up calculated in Table 2.2 shows that the auxiliary consumption is about 8 per cent at KSTPS while about 9 per cent in both NTPS and FTPS at full load condition. Figure 2.3 shows the sub-system-wise break-up (boiler, turbine or ash/coal handling) of auxiliary consumption at the three stations. It is seen that the turbine auxiliary system accounts for about 52 to 58 per cent of the total auxiliary consumption in the station while the boiler auxiliary system accounts for about 35 per cent of the total auxiliary consumption. The remaining auxiliary consumption is in ash handling and coal handling systems.

2.5 Reasons for high auxiliary consumption

The factors responsible for high auxiliary consumption can broadly be classified into three categories: plant/unit specific factors; external factors; grid specific factors (Figure 2.4).

16 Table

Auxiliary Equipment Nasik TPS Stage-11 (Unit 3,4,5) 3x210 MW Parli TPS Stage-H (Unit 3,4,5) 3x210 MW Korba STPS Stage-I (Unit 1,2,3) 3x210 MW

System 2.2. Rating No./Unit Full load Contri Rating No./Unit Full load Contri Rating No./Unit Full load Contri (kW) at full current bution (kW) at full current bution (kW) at full current bution

load (Amp) (MW) load (Amp) (MW) load (Amp) (MW) Equipment-wise Boiler ID Fan 1700 2 130 7.134 U-3: 2 110 6.767 1100 2 120 6.585 Auxiliary 1000 System U-4,5: 2 130 1300 FD Fan U-3: 650 2 32 1.756 U-3: 570 2 28 1.627 750 2 25 1.371 U-4,5: 2 32 U-4: 750 2 29

750

U-5: 650 2 32 break-up PA Fan 1250 2 125 6.858 1250 2 130 7.133 1250 2 125 6.858 Coal Mills 320 5 30 4.115 320 5 31 4.252 340 4 30 3.291 Turbine BFP 4000 2 300 16.46 4000 2 285 15.637 3500 2 305 16.735

Auxiliary of CEP 220 2 22 1.207 250 2 25 1.372 470 2 45 2.469

System auxiliary CWP 950 2 95 5.213 1350 2 145 7.956 685 2 65 3.081 CTP 710 2 90 6.885 680 2 82 5.624 1015 2 100 4.566 CT Fan Motors 45 28 40 1.932 105 9 155 2.406 43 16 1.08

LP Pump 130 1 0.405

Ash consumption Handling HP Pump ' 135 1 0.225 System Ash Slurry 160 & 1 & 1 285 & 0.794 210 2 17 0.933 135 1 0.354 Pump 120 175 Seal Water 30 1 24 0.041 25 2 32 0.102 - Pump Coal 5.35 5.75 4.718 Handling System Total 57.745 57.559 51.738 Auxiliary Consump tion at full load

Note: Abbrebriations: ID-Induced Draft, FD-Forccd Draft, PA-Primary Air, BFP-Boiler Feed Pump, CEP-Condensate Extraction Pump, CWP-Circulating Water Pump, CTP-Cooling Tower Pump, CT-Cooling Tower, LP-Low Pressure, and HP-High Pressure.

-4 70

KSTPS

B388 boiler R5559 turbine V77A ash & coal handling

Figure 2.3. Subsystem wise breakup of auxiliary consumption for three power stations

HIGH AUXILIARY CONSUMPTION

COAL SHORTAGES EXTERNAL FACTORS ■ POOR COAL QUALITY VARYING QUALITY

EXTRANEOUS MATERIAL

HIGH ASH CONTENT

BACKING DOWN OF UNITS GRID SPECIFIC ■ REACTIVE POWER GENERATION FACTORS

OPERATIONAL CONSTRAINTS - TECHNOLOGICAL - PLANT/ UNIT SPECIFIC ■ MANAGERIAL FACTORS - FORCED OUTAGES

Figure 2.4. Factors responsible for high auxiliar consumption

18 2.5.1 Plant/unit specific factors

Plant/unit specific factors can be further classified as follows:

0) Technical - relating to the level of technology of various equipment installed in the plant

(ii) Managerial - relating to the overall practices observed

(iii) Forced outages - occuring due to unforeseen circumstances or breakdown of equipment

(iv) Operational practices and constraints - constraints caused by external factors like poor coal quality that requires operation of additional coal mills compared to the designed numbers. Practices include idle running, improper operation of pumps etc. Thus better practices such as avoidance of idle running, parallel operation of pumps can also help reduce auxiliary power consumption.

The technological factors and related measures to reduce auxiliary consumption are described in detail in this work. The technical factor discussed in this study are only illustrative and general in nature, ie. these could be examined for all power plants. In addition to this, there may be a variety of opportunities specific to individual power plants to reduce the auxiliary consumption.

(a) Methodof control of auxiliaries. Some of the major auxiliaries require flow/ capacity adjustments to operate at varied loading conditions of the unit. With fixed speed drives this is achieved by valves, dampers, etc. Inlet guide control is commonly used for ID fan and vane or variable pitch control is used for FD fans. For BFP a hydraulic coupling with scoop control is quite commonly used in 210 MW units. Such control devices create turbulence in the path of the fluid, thereby drastically reducing the device efficiency and consume full power even when partly loaded. Instead, when the flow is controlled by varying the speed of the fan/ pump, smoother fluid flow results in higher efficiency for most of the operating region of the devices and hence for the system as a whole. The energy input is also reduced at part load, resulting in energy savings.

(b) Poorpart load heat rate. When the output (KW) needed from the unit is less than its capacity, the unit has to be operated at part load.The current design of the turbine requires same high inlet pressure at part loads as at full load. The inlet pressure is kept constant at part loads by throttling BFP discharge. Lot of energy is wasted in the throttling process. As a result, the heat rate (that indicates input heat per kilowatt-hour of output) deteriorates. The part load heat rate can be improved with sliding pressure operation of the units that allows for reduced inlet pressure at part loads. Similarly, in many of the units there has been a problem of high condenser back pressure at part loads that also causes poor heat rate.

(c) Lack of instrumentation and control (I&C) for proper combustion control. In the absence of total air and load auto control, especially with varying characteristics of

19 coal, it is difficult to run the unit with optimum excess air. Therefore instrumentation for auto air-load control is essential and has to be made operative. In addition, flame monitors provided have not been reliable. As a result operaters prefer to continue oil support, resulting in higher specific oil consumption. It is essential to provide reliable flame monitors with redundancy and continuous self checking features.

(d) Methodof field energization of electrostatic precipitators (ESPs). ESP is used to trap flyash from the flue gases. Flyash particles are charged and forced out of the gas stream using electric field force and collected in plates. The principal components of ESPs are two sets of electrodes. The first is composed of rows of electrically grounded vertical parallel plates, called the collection electrodes, between which the gas to be cleaned flows. The second set of electrodes are wires, called the discharge electrodes, that are centrally located between each pair of parallel plates. The wires carry a unidirectional, negatively charged, high voltage (between 20 and 100 kV, but typically 40 to 50 kV) current from an external source. The applied high voltage generates a unidirectional, non-uniform electric field whose magnitude is greatest near the discharge electrodes. When that voltage is high enough, a blue luminous glow, called corona, is produced around them. The corona is an indication of the negetively charged gas ions that travel from the wires to the grounded collection electrodes as a result of the strong electric field between them.

The performance and energy consumption of ESPs can be upgraded by pulse energization. Essentially this means that a high voltage pulse is superimposed on the base voltage to enhance ESP performance when operating with high resistivity ash. This is further refined by switching off the voltage to the ESP discharge electrodes during selective periods. This allows a longer period of time between energization cycles, which limits the potential for back corona. Therefore it is possible to reduce energy consumption. Savings in consumption up to 50 per cent are possible.

(e) Energy intensive ash handling system. The presently used wet system consists of a flushing system below each hopper and discharges the slurry into sluice way trenches below the ESP. From the sluice way trench the slurry is transferred to an ash slurry sump. From thereon to the final disposal area 2.5 km away involves two more stages of pumping of slurry. This involves a number of stages of pumping in addition to the power consumed in creating water head required to create vacuum for flushing of flyash.

This enormous amount of energy consumption can be reduced considerably by evacuating the flyash from hoppers directly by a dry pneumatic dense phase conveying system. In the dry pneumatic conveying system the only power consumer is the compressor and the material to air ratio is very high, resulting in much lower energy consumption per tonne of flyash conveyed. This option also offers the advantage of using flyash in future since most of the flyash based products require dry flyash. However, these systems have a limitation on conveying distance for dry flyash. Since the disposal areas are 2 to 5 km away and dry flyash does not have immediate use, an optimum solution would be a dry dense phase pneumatic conveying system up to an intermediate storage silo, adequately sized; slurry preparation below silo; and single

20 stage slurry pumping up to ash disposal area. Such systems are in use outside India and have the advantage of economizing on use of water.

(f) TechnologicaUlayout constraints in cooling water system. The condenser cooling water system involves pumping of water to a sump near the turbine hall and then using another set of pumps to pump water through the condenser to the cooling tower. Because of pump technology and layout constraints the number of stages of pumping required is very high, resulting in excessive energy consumption. In addition, the cooling tower technology used leaves tremendous scope for improvement. Improved design of fan blades of lighter material can result in significant savings, and can explored wherever feasible, such as for induced draft fans.

In addition, the cooling tower fan motors can be equipped with space heaters. Since these fan motors operate in highly humid environments, switching off some of them at low load periods, when fewer fans are required to be operated, leads to deterioration of insulation resistance of motor winding. However, keeping all the fans running, causes unnecessary auxiliary power consumption. This problem can be avoided by either retrofitting the motors with space heaters (which is expensive and inconvenient) or simply by making provision for application of 24 V AC power supply to the motor windings. The heating thus provided should be just sufficient to prevent moisture ingress in the insulation. The power consumption in this case is just a fraction of the normal power consumption of the motor.

2.5.2 Grid specific factors

(i) Backing down of units

Power demand in the system varies widely over a 24 hour period. The ratio of peak to off-peak demand is of the order of 1.8 to 2. This requires backing down of substantial thermal capacity during the night off peak hours, in order to regulate the frequency. Since the thermal (coal based) units are primarily designed for base load operation, backing down of units can have the following impacts on efficiency and therefore, on the environment:

(a) Unit efficiency is lower at part load and specific fuel consumption increases

(b) Percentage of auxiliary consumption is higher at part load because the reduction in auxiliary consumption is much less compared to reduction in generation due to backing down

(c) Operational constraints restrict the reduction in the number of auxiliaries in service during part load operation. For instance, due to unreliable operation of coal mills, all mills are required to be kept in service. Only the loading on the mills is reduced. Similarly, units are kept on oil support, thus increasing the fuel oil consumption.

(d) There are some technical constraints in reducing the output of auxiliaries during part loads operation, as discussed below.

21 Major auxiliaries like ID fans do not have variable speed drives (VSD). Control is effected by inlet guide vane control resulting in higher losses at part loads. Most of the auxiliaries have not been optimally sized from the point of view of part load operation and therefore the number of auxiliaries in service cannot be optimally selected. Some of the auxiliaries have technological constraints that prevent them from being shut down and therefore have to be kept in service even when not required. For example, at the Nasik TPS the cooling tower fan motors have not been provided with space heaters. If the fan motors are shut down during part load operation, the insulation resistance of the motor degrades due to very high humidity conditions, leading to damage to windings and other problems. Units are not designed for cyclic loading. A unit normally designed for "Sliding pressure operation" can result in substantial improvement in heat rate. The power lost in throttling (as is the case with existing units) is high, in the range of 50 to 75 per cent of full flow.

(ii) Reactive power generation by units

Due to mismatch of reactive power requirements in the grid and that generated, the system voltage dips. To stabilize the system voltage profile, generating units are asked to reduce the active generation and increase the reactive power generation from the unit. This is done by increasing the excitation which is limited by the cooling efficiency of the generator. When the allowable limits of the temperature are reached it is essential to reduce active power load on the machine.

2.5.3 External factors

(i) Coal shortages. Due to shortfall in coal receipts, thermal units operate with very little coal stocks and there have been a number of instances of units having to run at low loads or shut down due to coal shortages. This results in low PLF for the unit as well as the plant, and increases the auxiliary consumption of the unit.

(ii) Poor coal quality. It is a common experience in thermal power plants that the coal received deviates from design values in terms of calorific value as well as ash content. Table 2.3 shows the difference in qualities of coal received at the Nasik TPS.

Table 2.3. Typical coal analysis for NTPS

Parameters Average Coal Received Plant Design Coal

Fixed Carbon 29.5% 37.3% Volatile Matter 18.63% 27.7% Moisture 7.04% 10% Ash 44.88% 25% Higher Heating Value 2825 kcal/kg 5000 kcal/kg

22 If the coal received is one grade inferior coal to the design coal, it implies a difference of 1,000 kcal/kg in heating value and a 7 to 8 per cent difference in ash content.

Coal is received from many sources, widely varying in quality. Such wide variation in moisture, ash content, volatile matter and calorific value of coal seriously affects the flame stability and changes the flame front. In the absence of total air and thermal load auto control in most stations (excess air measurement and auto control is now under implementation at Nasik and Parli TPS) operator confidence is low. In addition, flame monitors are also unreliable. All this results in use of oil support even though it is not required above a minimum load of 100 MW on a 210 MW unit.

In addition to the above, there is a wide assortment of extraneous material like stone, shale, clay metallic pieces etc. in the coal received. This results in inefficient loading operation, causing damage to coal handling equipment. High rate of wear and tear of coal handling equipment, specially the mills, results in non-uniform coal size in the output from the mills, which in turn affects combustion stability. This also increases the down time of coal mills and limits the number of mills available, leading to load restrictions on the units.

The ash content in non-coking coal used in thermal power stations in India, is substantially high, ranging from 35 to 55 per cent. Some of the adverse effects of the high ash content, on unit operation and auxiliary consumption are:

(a) Lower calorific value of coal and additional requirement of handling and milling capacities. The existing design of power plants does not consider the effect of high particulate presence on heat transfer and estimated value of gas temperatures. This quite often leads to high exit flue gas temperatures and consequent loss of efficiency.

(b) Higher loading of Electrostatic Precipitators (ESPs). Compared to design coal, the additional quantity of fly ash to be handled for worst quality coal for a 3x210 MW station is approximately 450 tonnes per day (TPD). This is worked out considering an average heat rate of 2640 MCal/MU. However, providing extra stream or extra field for ESPs to capture this extra ash has an impact on the length of duct and consequently the ID fan capacity. Due to this limitation the ESP upgrade efforts are limited to reducing stack emissions to the extent possible and reducing energy consumption with pulse energization of ESPs.

(c) The ash handling system has to be run for longer durations because of increased flyash quantity to be handled. The additional 450 TPD of flyash to be handled means extra operation of the flyash systems (4-6 hours), that results in high auxiliary consumptions. Normally the ash handling systems are designed for 16 hours of operation per day, but increased ash may require them to operate for 20 hours or more.

(d) Fouling of heat transfer surfaces, resulting in forced outages due to tube leakages.

23 2.6 Evaluation of options for reduction of auxiliary consumption: case studies

The external grid management factors, coal quality problems and plant related factors responsible for high auxiliary consumption have been dicussed earlier in this chapter. A good grid management programme and improvement in the PLF can reduce auxiliary consumption of the units substantially. This study, however, focuses on strategies to reduce auxiliary consumption through improvements in plant/unit related factors. For this, plant specific case studies have been taken up to evaluate various options for reduction of auxiliary consumption. The power stations which were identified for the specific case studies presented here are:

Nasik Thermal Power Station (NTPS), Stage-II (Units-3,4,5) of MSEB Parli Thermal Power Station (FTPS), Stage-II (Units-3,4,5) of MSEB Panipat Thermal Power Station (PNTPS), Unit-5 of HSEB Korba Super Thermal Power Station (KSTPS), Stage-I (Units- 1,2,3) of NTPC

As seen from Figure 2.2, in NTPS and KSTPS auxiliary consumption is in the range of 8 to 9 per cent (Category-B) while FTPS and PNTPS, both have significantly high auxiliary consumption, in the range of 11 to 12 per cent. Thus, this diversity in auxiliary consumption figures among different stations have been analyzed to provide an insight into the particular plant/ unit specific factors which are important.

2.6.1 Variable speed drive for ID fans

Large steam generators require large amounts of air to be sucked in and gases and ash thrown out. Large fans are used for this. There are two types of fans in use today, Forced Draft (FD) Fan and Induced Draft (ID) Fan.

FD fans are placed at the air entrance to the air preheater and put the entire system up to the stack entrance under positive gauge pressure. ID fans are located in the gas stream between the air preheater and the stack, either before or after the dust collector. The discharge is at atmospheric pressure and the entire system is placed under negative gauge pressure. These fans handle hot gases, including the original air, the gas equivalent of the fuel added, and leakages into the system.

ID fans are normally loaded to about 70 per cent of their design capacities even at full plant load. Therefore, the potential for energy savings through use of variable speed drives (VSDs) is substantial. The static speed control methods (used in VSDs) for such large rating motors employ a converter fed synchronous motor. The scheme basically comprises two converters, one on the line side and another on the machine side. The line side converter functions as a rectifier and the one on the machine side as an inverter feeding the synchronous motor with variable voltage and variable frequency, therby controlling the speed.

The VSDs have several advantages over currently prevailing technology of hydraulic coupling and fixed speed motor drives. These include, smooth control of air and water flow over a wider range; absence on limitation of number of starts; no voltage dips in the system from direct on-line starting of large size machines; increased efficiency over wide operating speed

24 range; increased life of motors due to soft starts; simple arrangements, no necessity for large cooling equipment for hydraulic coupling; reduction in size of unit/station transformer rating; reduction in switchgear fault level; totally static equipment hence less maintenance.

The system consists of independent channels, each comprising isolation transformer, source converter (rectifiers), DC link reactor and load converter (inverter). The availability of the system is greatly improved since each channel is sized to 100 per cent fan rating. The isolation transformers serve to step down auxiliary bus voltage to required motor voltage and reduce fault levels of converters. A microprocessor based system can be provided for control, interlocking and protective functions of the drive.

The capital cost of the complete VSD system (for one generating unit) has been estimated to be of the order of Rs. 30 million (based on a cost of Rs. 1.2 million/kW of drive rating for similar drives for a 500 MW unit and suitably adjusted to 1994 prices). The total capital expenditure for NTPS, FTPS or KSTPS (comprising 3x210 MW generating units) would thus be Rs. 90 million. The total annual savings with the VSD system are calculated on the basis of actual running hours, load data and using estimated kW savings from VSDs, reported in the literature. Assuming energy price @Rs. 2.5/Unit, which is the maximum average tariff charged by MSEB, techno-economic studies are worked out (Box 2.1). This price has been used to evaluate the benefits from VSD because the energy so saved could be despatched to the grid for sale.

2.6.2 Variable speed drive for boiler feed pump motors

In the existing scheme 3x50% BFPs of 4MW capacity each are driven by individual fixed- speed squirrel-cage induction motors. To economize on BFP pumping energy costs, by avoiding throttling losses across feed-water control valves at part loads, a variable speed hydraulic coupling between pump and motor is provided. In the absence of confirmation from the manufacturer, it is assumed that it is possible to drive the BFP and the booster pump with the same drive. Therefore, pump costs have not been considered in capital estimates. The alternate system considered consists of 3x50% BFPs with individual driven synchronous motors, the speeds of which are varied by variation of input power using LCI drive. A comparison has been made between the existing BFP drive system consisting of 3x50% 4 MW motor each with hydraulic coupling between pump and motor, and 3x50% alternate system pumps with same rating directly coupled to motor; the speed of motor is varied through LCI drive. The capital cost of the complete VSD system has been taken to be Rs 60 million/Unit (three drives and accessories) i.e. a total capital cost of Rs 180 million for NTPS, FTPS or KSTPS. The savings accruing from VSD in BFP motors are worked out below (Box 2 .2 ).

2.6.3 Pulse energization retrofit in electrostatic precipitators

Pulse energization involves modification of conventional ESP power supplies. Essentially, a high voltage pulse is superimposed on the base voltage which is applied to wire or a rod discharge electrode which increases the density of emitting points and thereby ESP performance. The duration of the pulse is short enough to avoid arcing. A further refinement of this technique is intermittent energization (IE). While the ESP controls would otherwise apply unfiltered full-wave or half-wave rectified DC voltage to the discharge electrode, it

25 . Variable Speed Drive for ID Fans

NTPS

Energy savings per year = 15.645 MU Benefit per year (@Rs. 2.5/Unit) = Rs. 39.1125 million Total investment in VSD = Rs. 90 million Payback period (Discounted: @ 14% interest) = 2.6 years

PTPS-A

Energy saving per year = 9.667 MU Benefit per year (@Rs. 2.5/Unit) = Rs. 24.1675 million Total investment in VSD = Rs. 90 million Payback period (Discounted: @ 14% interest) = 4.7 years

KSTPS

Energy saving per year = 13.715 MU Benefit per year (@Rs. 2.5/Unit) = Rs. 34.2875 million Total investment in VSD = Rs. 90 million Payback period (Discounted: @14% interest) = 3.0 years

PTPS-B

Energy saving per year = 3.254 MU Benefit per year (@Rs. 2.5/Unit) = Rs. 8.135 million Total investment in VSD = Rs. 30 million Payback period (Discounted: @ 14% interest) = 4.6 years

Box 2.1 facilitates the switching off of supply during selected periods. This serves two purposes: it allows a longer period between energization cycles, limiting the potential for arcing or back corona, and reduces energy consumption, without reducing charge on the particles. The retrofit of ESP with IC control system can enhance performance and achieve a reduction of about 20 per cent in emissions and a reduction of 50 per cent in energy consumption.

An ESP modernization scheme to reduce emissions and power consumption is under way at both NTPS and FTPS. Wherever possible, mechanical improvements such as improving the flue gas flow path or increasing the specific collection area (SCA) have to be incorporated in the augmentation/retrofit plan. However, this is very site specific. The capital cost of a pulse energization retrofit is assumed to be Rs. 120 million. This is based on available information from MSEB. However, although an annual benefit of Rs. 11.2 million accrues there is no feasible payback period for the scheme (Box 2.3).

26 Variable Speed Drive for Boiler Feed Pump Motor

NTPS

Energy saving per year = 41.283 MU Benefit per year (@Rs. 2.5/Unit) = Rs. 103.2075 million Total investment in VSD = Rs. 180 million Payback period (Discounted: @14% interest) = 1.9 years

PTPS-A

Energy saving per year = 25.52 MU Benefit per year (@Rs. 2.5/Unit) = Rs. 63.8 million Total investment in BFP = Rs. 180 million Payback period (Discounted: @14% interest) = 3.3 years

KSTPS

Energy saving per year = 39.731 MU Benefit per year (@Rs. 2.5/Unit) = Rs. 99.3275 million Total investment in BFP = Rs. 180 million Payback period (Discounted: @14% interest) = 2.0 years

PTPS-B

Energy saving per year = 9.2832 MU . Benefit per year (@Rs. 2.5/Unit) = Rs. 23.2075 million Total investment in BFP = Rs. 60 million Payback period (Discounted: @14% interest) = 2.9 years

Box 2.2

Pulse-Energization Retrofit for ESP

Estimated savings in power = 550 kW consumption in ESP

Total operating hours = 8000 Energy saving/annum = 4.5 MU Benefit/annum (@Rs. 2.5 /unit) = Rs. 11.2 million Capital cost of retrofit = Rs. 120 million Payback period (Discounted: @ 14% interest) = Infeasible

Box 2.3

27 2.6.4 Retrofit of ash handling system

The existing ash handling system can be retrofitted by employing a dry flyash evacuation system. The proposed system consists of a dense phase vessel below each hopper, conveying flyash accumulated in the hoppers to an intermediate silo. Each dense phase vessel operates as per the requirements, based either on a timer or level of flyash in the hopper. From the storage silo, the flyash is discharged into a mixing tank where the dry flyash is converted into slurry and pumped directly with high pressure slurry pumps to the ash pond area. The method involves pumping only at a single stage. In the specific case of NTPS, where an efficient last stage slurry pumping station has been installed, the scheme could be modified to reduce capital costs. In the modified scheme, slurry from the mixing tank of the storage silo could be allowed to flow in the sump of the last stage pumping station.

While the final solution will require a detailed study with complete data regarding the existing system and more interaction with equipment suppliers, an attempt has been made to arrive at the indicative economic figures with the information available. For this purpose, replacement of the wet system with a dense phase dry flyash collection system up to an intermediate distance of 500 m, where it is collected in a 900 T capacity silo, is considered (one day storage of a single 210 MW unit). From the silo, ash can be collected in dry form for selling, if required, or it can be converted into slurry and pumped to the dump area with slurry pumps. The annual energy consumption per unit in the existing system is of the order of 8 MU. Energy savings of 4.7 MU can be achieved annually from the alternate system. This will yield an annual benefit of Rs. 11.7 million. With a capital cost of Rs. 80 million for the alternate system the payback period works out to 13.8 years (Box 2.4).

2.6.5 Utilization of waste steam

A 210 MW unit has an air-conditioning load of approximately 175 tonnes of refrigeration (TR) of which, the switchyard control room, offices, I&C lab are generally common to more than one unit. The distribution of load is shown in Table 2.4.

A separate air-conditioning system is generally adopted for the ESP control room and switchyard control room. To meet the requirements of air-conditioning the control room, lab, etc., the central air conditioning system adopted consists of compressor/condenser units in the A.C plant room; condenser cooling water circuit, including cooling water pumps, cooling tower, piping etc.; chilled water circuit, including chilled water pumps, piping upto air handling units (AHU) and back etc.; AHU and supply and return air distribution system from AHU to load point.

28 Retrofit of Ash Handling System

Power consumption of a typical 210 MW ash handling system = 8 MUs

Proposed System

MPW Pump (2x30 kW) 60 kW Slurry Pump (2x110 kW) 220 kW Seal Water Pump (1x7.5 kW) 7.5 kW Air Compressor (2x155 kW) 310 kW Fluidising Air Blower (1x26.5 kW) 26.5 kW

Total = 624 kW

Operating hours per day 16 Total energy consumption per annum 3.3 MUs Energy savings per annum 4.7 MUs Savings per annum (@Rs. 2.5/Unit) 11.7 million Capital cost of the plant Rs. 80 million Payback period (Discounted: 14% interest) 13.8 years

Box 2.4

Table 2.4. AC load distribution in a typical 210 MW unit

Unit Control Room 75 TR Switchyard Control Room (common for more than 1 unit) 50 TR ESP Control Room 20 TR Office, I&C Lab, etc. 30 TR

Total unit load: 175 TR

In a vapour absorption system, steam is used to produce chilled water. Therefore, when a vapour absorption system is used, the compressor/condenser unit is replaced by the compact absorption unit. A small capacity condenser cooling water circuit is still required but generally the pumping head requirement and piping requirement is not high since cooling tower can be located in the vicinity of the absorption unit. A new chilled water circuit is required to be laid up to the existing AHUs and connnected to the AHU of the existing system with a suitable control valve arrangement. Waste steam is generally available from the steam used for oil tank heating (that contains low sulpher (LSHS) oil, and hence also known as LSHS tank) or the flashing steam from continuous blow down (CBD). The CBD is to eject impurities from the steam.

Steam is generally used for LSHS tank heating and this steam is flushed to the atmosphere. Though no measurement is available of the quantity flushed outs available, it has been

29 estimated to be sufficient for one 75 TR vapour absorption unit. However, in case of continuous blow down, the steam is available for each unit which means an absorption unit of 75-100 TR capacity can be installed to utilise this steam. Thus, the vapour absorption system is economically very attractive.

The capital cost of a new 75 TR vapour absorption machine is about Rs. 1.8 million. Typically, the location of LSHS tanks where this unit could be located is 500 m away from the AHU room. The cost of the additional chilled water and cooling water system required, will be approximately Rs. 1.1 million. Based on these capital costs the payback period works out to two years (Box 2.5). If one additional 75 TR unit is installed using CBD, the total energy would be of the order of 3x0.58 or 1.74 MU. Total energy savings for the station will be of the order of 2.3 MU.

Waste Steam Utilization

Capital Cost of Plant

Vapour Absorption Unit (VAU) Rs. 1.8 million Air Handling Unit (AHU) Rs. 0.4 million Chilled water piping Rs. 0.5 million Condenser, cooling water pumps, cooling tower etc. Rs. 0.2 million

Total capital cost Rs. 2.9 million

Comparison of Operating Costs VAU Existing System Capacity 75 TR 75 TR Power Consumption 1.9 kW 75 kW Annual operating hours 8000 8000 Annual energy cost (@2.5 Rs./unit) Rs. 38,000 Rs. 1,500,000 Maintenance cost Rs. 15,000 (@Rs. 200/TR) Rs. 60,000 (@Rs. 800/TR) Total annual operating cost Rs. 53,000 Rs. 1,560,000 Net savings Rs. 1.507 million Payback period 2.2 years (discounted @14% interest)

Box 2.5

2.6.6 Cooling tower design improvement

While change of layout of cooling tower system in an existing station may not be feasible, some improvements related to cooling tower fans are definitely cost effective. There is scope for retrofit of cooling tower fans of the circulating water system in the following areas:

30 (a) Replacement of fan blades with aerodynamically designed blades of lighter material. This has already been implemented at Nasik and can be planned for Parli. Therefore, no economic analysis has been carried out.

(b) For preventing ingress of moisture in the motor winding during night times at low loads, a system of application of 24 volts on the motor winding is recommended. In the specific case of Nasik this will result in annual savings of 1.1 MU amounting to Rs. 2.75 million. The payback period is less than a year (Box 2.6).

Cooling Tower Fan Motor Retrofit

Power consumption by 1 motor (3-phase, 24 Volts) 0.4 kW Number of fans required to be switched off 10 Power consumption by 24 V supply for 10 fans 4 kW Energy consumption by 10 fans at 8 hrs/day 32 Units Net energy consumption in 1 year 9600 Units

Power consumption of Cooling Tower Fan 45 kW Energy savings from switching off 10 fans at 8 hrs/day 3600 Units Energy savings in 1 year 1.08 MUs

Total energy saving/annum 1.07 MUs Total annual savings (@Rs. 2.5/Unit) Rs. 2.675 million Capital cost Rs. 1 million Payback period (Discounted @ 14%) 5 months

Box 2.6

2.7 Evaluation of benefits of recommended options

It can be seen from Table 2.5 that most of the options have a payback period below 3 years. However, it is seen that for FTPS, the payback periods are significantly higher than those of NTPS or KSTPS. This is because of low PLF at FTPS due to which energy sayings and hence cost savings are affected.

31 Table 2.5. Evaluation of benefits of recommended options

Options Capital Annual Potential Annual Payback Period Cost Energy Saving Savings (Years) (Rs.Million) (MU) (Rs.Million) Discounted @14%

VSD Nasik 90 15.7 39.113 2.6 for ID Fan Parli 90 9.7 24.147 4.7

Korba 90 13.715 34.2875 3.0

Panipat 30 3.254 8.135 4.6

VSD Nasik 180 41.3 103.21 1.9 for BFP Parli 180 25.5 63.8 3.3

Korba 180 39.731 99.3275 2.0

Panipat 60 9.283 23.2075 2.9

Waste Steam Utilization 2.9 0.6 1.51 2.2

ESP Field Energization 120 4.5 11.25 Not Economical*

Alternate Ash Handling 80 4.7 11.75 13.8 System

Cooling Tower Design 1 1.1 2.75 0.5 Improvement (NTPS)

* The conventional discounted (14%) payback period calculation yields infeasible payback period. However, it is justified since besides energy savings, it reduces emissions substantially, for which no credit was taken. It is justified on this ground.

Note: The data are for 3 units of 210 MW for all power stations except Panipat, that has only one unit.

Source: IGIDR study

2.8 Emission reduction from reduction in auxiliary consumption

Energy savings from different options in the auxiliary system, discussed in the previous section, also implies reduced emissions of GHGs and other gases to the atmosphere. The annual energy savings for one unit of 210 MW plant for the four case study plants work out between 15.4 MU (for Parli) and 22.6 MU (for Nasik). Corresponding reduction in auxiliary consumption as a percentage of electricity generation for these units is 1.53% and 2.2% respectively. If an average auxiliary consumption reduction of 19 MU is considered for 80 units of 210 MW (about 70% of the total 120 units), energy savings work out to 1520 MU and C02 emissions savings are approximately 1.5 million tonnes per annum.

Benefits in terms of reduced emissions have also been evaluated for various options, considering the remaining life of the plants to be 15 years. The emission coefficients used for

32 different thermal power stations have been derived using the calorific value associated with the grade of coal actually received by that station and the station average heat-rate, available from respective station data. Table 2.6 shows the coefficients for different pollutants, viz., C02, S02 and NOx for the four different power stations considered for the case studies. Overall energy and C02 savings and cost of C02 emissions reductions from various options are given in Table 2.7 and the reductions in S02 and NOx emissions are given in Table 2.8.

Table 2.6. Emission coefficients for different power stations

Power Station C02 Emission Coefficient S02 Emission Coefficient NOx Emission Coefficient (Tons/MWh) (kg/MWh) (kg/MWh)

Nasik TPS 1.0 2.67 4.66 Parli TPS 1.09 3.49 5.06 Korba STPS 0.99 3.45 4.60 Panipat TPS 1.46 4.4 6.79

Source: IGIDR Study

It can be seen that the cost of C02 reductions varies from about $1 per ton to $55 per ton (1 US$ = Rs. 35). As Table 2.7 indicates, the proposed options for reduction of auxiliary consumption result in energy savings of about 1001 MU at NTPS, 691 MU at FTPS, 965 MU at KSTPS and 351 MU at PNTPS over the remaining estimated life of 15 years of the plants. The corresponding C02 savings are 1, 0.75, 0.96 and 0.37 million tonnes for NTPS, FTPS, KSTPS and PNTPS respectively. Figures 2.5 to 2.8 show the potential for C02 savings and associated cost of various options for the case study plants.

2.9 Other plant-related technical options for energy saving

Some of the other measures for improvement of thermal power station efficiency are discussed below. These are however, not analyzed in detail.

2.9.1 Improvement in power factor of power plant auxiliaries

The auxiliaries consume significant amount of power and yet not enough attention has been paid to improve their power factor. In some cases, the PF was observed to be as low as 0.85. It is easier to improve the PF at the auxiliary consumption point. However, effect of the power factor improvement on supply voltage from the generating station need to be considered. Therefore this alternative needs a careful study before implementation.

33 4^U) Table 2.7. Contributions of different potential options for CO2 savings

Energy Savings, MU C02 Emission Reduction (’000 Tons) Cost of C02 Reduction (Rs./Ton)

NTPS FTPS KSTPS PNTPS NTPS FTPS KSTPS PNTP NTPS FTPS KSTPS PNTPS

VSD for ID Fan 234.7 145 205.7 48.8 234.7 158 203.6 52 383.5 569 442 303

VSD for BFP 619.3 383 596 139.3 619.3 418 590 146 290.7 430.6 305.1 212

Waste Steam Utilization . 8.8 8.8 8.8 8.8 8.8 9.6 8.7 10 329.5 302 333.3 163

ESP Field Energization 67.5 67.5 67.5 67.5 67.5 73.8 66.8 71 1778 1626 1796.4 876

Alternate Ash Handling System 70.5 70.5 70.5 70.5 70.5 76.9 69.8 75 1134.8 1040.3 1146.1 560

Cooling Tower Design Already 16.5 16.5 16.5 - 18 16.3 18 - 55.6 61.4 30.4 Improvement existing

Total 1000.8 691.3 965 351.4 1000.8 754.3 955.2 369

Source: IGIDR Study

Table 2.8. Contribution of different potential options for S02 and NOx savings

S02 Reduction (Tons) NOx Reduction (Tons) NTPS FTPS KSTPS PNTPS NTPS FTPS KSTPS PNTPS VSD for ID Fan 626.65 506 709.7 214.7 1093.7 733.7 946.2 331.4 VSD for BFP 1653.53 1336.7 2056.2 612.9 2885.9 1938 2741.6 945.9 Waste Steam Utilization 23.5 30.7 30.4 38.7 41 44.5 40.5 59.8 ESP Field Energization 180.2 235.6 232.9 297 314.6 341.5 310.5 458.3 Alternate Ash Handling System 188.25 246 243.2 310.2 328.5 356.7 324.3 478.7 Cooling Tower Design Improvement - 57.6 56.9 72.6 - 83.5 75.9 112 Total 2819 2706 3329.3 1546.2 3780 3778.7 4439 2386

Source: IGIDR Study Figure

COST OF REDUCTION (RS/TON)

E: D: B: A: (Thousands) C: 2.5. Cooling Alternate Variable Variable

Marginal ESP Waste

Field

Steam

cost

Tower

Speed Speed Ash

Energization

curve

Utilization Handling

Design Drive Drive

for C02

for for

emission

EMISSION Improvement

System

BFP ID

REDUCTION Fan

Motor (Thousands) reduction

(000

TONS)

NTPS 35 Figure 36

COST OF REDUCTION (RSfTON)

(Thousands) B: A: F: E: D: C: 2.6. Cooling

Variable Variable

Marginal Waste Alternate ESP

Field

Steam

cost

Tower

Speed Speed Ash

Energization

curve

Utilization Handling

Design Drive Drive

for COZ

for for

emission EMISSION Improvement

System

BFP ID

REDUCTION Fan

Motor reduction

(000

TONS)

PTPS Figure

COST OF REDUCTION (RS/TON)

E: B: (Thousands) F: D: C: A: 2.7. Cooling Alternate Variable Variable

Marginal 0.4 0,6 0.6 0.7 0.8 0.9 0.3 1.1 1.2 1.3 1.4 1.S 1.6 1.7 ESP Waste

- - — - - — — ------

Field

Steam

cost

Tower

Speed Speed Ash

Energization

curve

Utilization Handling

Design Drive Drive

for C02

for for

emission

EMISSION Improvement

System

BFP ED

REDUCTION Fan

Motor (Thousands) reduction

(000

TONS)

KSTPS Figure 38

COST OF REDUCTION (RS/TON)

(Thousands) F: E: D: B: C: A: 2.8. Cooling Alternate Variable Variable

Marginal ESP Waste

Field

Steam

cost

Tower

Speed Speed Ash

Energization

curve

Utilization Handling

Design Drive Drive

for C02

for for

emission

EMISSION Improvement

System

BFP ID

REDUCTION Fan

Motor reduction

(TOO

TONS)

PNTPS 2.9.2 Sizing of auxiliaries

In the four case study power plants, considerable variations in size of auxiliaries and their full load current ratings were observed. All the units were of 210 MW rating, but if smallest rated auxiliaries from the four plants were chosen, the total auxiliary consumption works out to 51.7 MW. If highest rated auxiliaries were chosen, the consumption figure reaches 57.6 MW (see Table 2.9). The actual auxiliary consumption in the plants was between these limits. Although, higher sizing of auxiliaries in some cases may be due to site specific, or plant specific reasons, in others it may be due to more than necessary margin on capacity. Detailed examination and evaluation of option to replace existing auxiliaries with properly sized auxiliaries may indicate the potential reduction in auxiliary consumption as a result of this.

Table 2.9. Equipmentwise break-up of auxiliary consumption

Equipment Rating Nos/Unit Full load Contribution kW current MW

Boiler Auxiliaries:

ID Fans 1000-17000 2 110-130 6.59-7.13 FD Fans 570-750 2 25-32 1.37-1.76 PA Fans 1250 2 125-130 6.86-7.13 Coal Mills 320-340 4-5 30-31 3.29-4.25 Turbine Auxiliaries:

BFPs 3500-4000 .2 285-305 15.64-16.74 CEPs 220-470 2 22-45 1.21-2.47 CWPs 685-1350 2 65-145 3.08-7.96 CT Fan Motors 43-105 9-28 40-155 1.08-2.41

Ash Handling System:

LP Pumps 130 1 0.41 HP Pump 135 1 0.23 Ash Slurry Pump 120-210 1-2 0.35-0.93 Seal Water Pump 25-30 1-2 0.04-.10

Coal Handling System: 4.72-5.75 Total Aux. Consumption: 51.74-57.56

2.9.3 Coal beneficiation

A very high percentage of coal received at the thermal power stations in India is inferior grade coal, E, F or G. Due to progressive mechanization of coal mining and the trend of increasingly higher percentage of coal coming from open cast mining, the ash percentage in such coals has been increasing. Besides the inherent ash content in coal, this increase has been due to mixing up of extraneous matter like shale and stones. The objective of limited beneficiation in such a case would be the removal of extraneous matter. This limited beneficiation serves the purpose of power plants, since any coal quality close to the design

39 requirements is desirable as the units are equipped to handle this ash efficiently. The analysis of trends shows an increase in the percentage of extraneous matters like shale and stones. Some of the economic evaluation studies have proved that beneficiation is a viable alternative, taking into account the benefits due to higher heat contents of beneficiated coal and reduced transportation costs. Additional benefits like improved heat rate, savings in mill running costs, etc. make the option still more attractive.

2.9.4 Turbine uprating

An extensive renovation and modernization of the units can result in improving the heat rate, extending the useful life as well as increasing the rating of the unit in some cases. Uprating of 210 MW turbines has been achieved in a number of power stations in Poland on 210 MW units of the same design. In addition to uprating the units to deliver 235 MW for the same steam parameters using the existing reserves in the design, it is also possible to achieve increased efficiency and flexibility in operation to enable restart from any thermal conditions, i.e to suit non-base load operations. Uprating would also extend the life of the unit and enable vacuum and efficiency to be achieved in spite of the higher temperature of cooling water.

2.9.5 Other measures

There are several other possible measures to reduce auxilary consumption. Some of these, that can be explored are use of turbo-pumps in place of BFPs, use of 11 KV motors, use of LCI drives for fan motors etc. Feasibility of a centralized coal mill for plants that are in a cluster can also be examined. It can improve reliability besides reducing electricity consumption. This has been implemented at Vijayawada TPS.

40 3 A systems approach to estimate savings from reduction in auxiliary consumption

3.1 Introduction

Power system operations planning is of crucial importance in view of the fact that sub-optimal operation of the system might not only mean several billion rupees being wasted by utilizing inefficient and expensive generating units more than required, but also shortages of power in various sectors directly leading to a negative impact on economic growth. Efficient operations planning involves a broad range of activities, starting from fuel supply decision making to power generation scheduling, power transmission and inter-utility coordination. In the Indian context, efficient management of the existing system merits immediate attention because current operating practices are far from satisfactory.

This chapter, addresses the important issue of power plant efficiency improvement through reduction of auxiliary consumption. Generating unit-wise characteristics have been considered in a comprehensive systems modelling framework to estimate the savings that can accrue from the measures described in Chapter 2. Thermal power generation in India has traditionally been based on steam turbine technologies with coal as the primary fuel. The issues related to the supply of coal to the power sector merit special attention because of the sector’s increasing reliance on coal.

Coal supply issues have a direct bearing on power plant capacity utilization and plant efficiency. Poor quality of coal, inadequate supply and transportation bottlenecks lead to increased system costs and higher auxiliary consumption. Due to shortfall in coal supply to power stations, the thermal units have to operate with very little coal stocks and there are instances of some of the units being forced to run at low loads or shut down due to coal shortages. This results in low PLF for the unit and hence increases the auxiliary consumption. Poor quality of coal may have serious impacts. For example, in the coal received by a power station from many sources there are wide variations in moisture, ash content, volatile matter and calorific value which may seriously affect the flame stability. More oil support may be required in such circumstances, even though this is undesirable. The presence of extraneous material in coal may lead to damages in coal handling equipment and inefficient loading operation. High ash content in coal means additional coal handling and milling as well as ash handling requirements. This leads to a significant increase in power plant auxiliary consumption.

Bottlenecks on the coal supply side lead to sub-optimal system operations due to constraints on production capacity in specific mines or on transportation capacity to allocate coal to power stations, or both. These bottlenecks need to be identified and a strategy for removing them needs to be formulated to achieve optimal system operation. If there is inadequate coal production, a short run production expansion strategy needs to be formulated. This production expansion must take into account the marginal benefit from capacity expansion and the associated cost.

41 In the present study, an attempt has been made to analyze the importance of reduction of auxiliary consumption from thermal power plants considering a system-wide perspective of the Indian power system. The NATGRID model [9], developed here at the Indira Gandhi Institute of Development Research, has been used to simulate various scenarios for reduction of auxiliary consumption.

3.2 The NATGRID model: an overview

NATGRID is a linear programming model [9] with the total system cost as the objective function to be minimized, subject to a set of constraints. The system comprises 19 utilities (State Electricity Boards, SEBs in India) of the four major electricity regions. It contains details of 210 generating units, 90 inter-utility transmission lines, 23 major coal fields and 97 power station-coal field linkages for the existing system.

Objective function

The cost objective function has been defined to be the total cost of generation and unmet energy. The operating cost for coal based generation includes costs of coal production and transportation. For all other modes of generation, viz., hydro, gas and nuclear, the generation cost is put in aggregate terms per MWh. The objective function includes the cost of unmet energy which represents the opportunity cost of shortage of electricity in any state.

Constraints

(i) Generation capacity constraints. The generating units; are constrained by the power output limit or the MW capability of the unit in all time blocks.

(ii) Transmission capacity constraints. Transfer of power across the states along each voltage class is limited by total transmission capacity of all lines in that voltage class in terms of MW.

(iii) Demand constraints. In each state and each time block the demand minus unmet energy must be equal to the sum of the state’s own generation, the central sector ’s contributions, imports from other states minus exports. The loading being constant within a time block, the energy demand (MWh) constraint and power demand (MW) constraints are equivalent.

(iv) Hydro energy constraints. In addition to capacity constraints, hydro units are also constrained by the hydro energy availability in a period. While a unit can take a maximum load based on its MW capability, the total number of hours for which the unit can be run is limited by the total MWh potential in a period.

(v) Central sector’s share contracts. These represent the existing practice of allocating a fixed quota of central sector generation to the states.

42 (vi) Calorific balances forcoal based units. The energy generated must be supported by equivalent tonnage of coal supplied to the generating unit considering its efficiency and the calorific value of coal supplied.

(vii) Coal production capacity constraints. The total coal production from a mine is limited by mine-level considerations like manpower availability, mining equipment capacity, etc.

(viii) Coal transportation capacity constraints. Given the number of wagons, trucks, loading and unloading capacity in each route by each mode, there is a limit to the total amount of coal that can be transported.

3.3 Analysis and scenarios

The NATGRID model has been used to estimate the impact of reduction of auxiliary consumption on the Indian power system. Several scenarios have been considered on the total system auxiliary consumption figures. Comparisons have been made between the base case operations (i.e. with actually existing auxiliary consumption figures) and a scenario where in auxiliary consumption of plants exceeding 12 per cent is reduced to 12 per cent; that of plants exceeding 11 per cent is reduced to 11 per cent, etc. It is seen from Table 3.1 that when auxiliary consumption is reduced, the system costs reduce significantly. If the system auxiliary consumption is restricted to 8 per cent or less, the cost savings are Rs. 1,023 million annually. 1,459 MU of additional energy requirements of the system can be met, and there is a reduction in C02 emissions to the tune of 218,000 tons per year. However, since unmet energy is also met from auxiliary consumption reductions, this has to be added to calculate total energy savings. When this is done, the C02 savings range from 0.34 to 1.23 million tons per year.

43 Table 3.1. Effect of reduction of auxiliary consumption considering national grid operation

Parameters Auxiliary Consumption

Actual Restriced Restricted Restricted Restricted Restricted 12% 11% 10% 9% 8%

Total System Operating Cost (Million Rs.) 46,215 45,284 45,164 45,101 44,692 45,188

Unmet Energy (MU) 15,811 15,343 15,283 15,010 14,707 14,352

Total Generation (MU) 45,757 45,741 45,759 45,788 45,744 46,778

Total Auxiliary Consumption (MU) 3,246 3,187 3,131 3,017 2,840 2,586

Coal Based Generation (MU) 30,104 30,102 30,101 30,095 30,086 29,906

Total Coal Supplied (’000 Tons) 22,101 22,100 22,099 22,095 22,078 21,965

Average Generation Cost (Rs./kWh) 1.01 0.99 0.987 0.985 0.977 0.966

Average Thermal Units Auxiliary Consumption (%) 10.8 10.6 10.4 10.02 9.4 8.6

Annual C02 Reduction (’000 Tons) ® - 340 385 589 818 1239

Rate of Emission (Tons/kWh) 0.7239 0.7237 0.7235 0.723 0.723 0.70

Source: IGIDR Study

® Note: Since contribution to unmet energy is also from auxilary consumption reductions. This is also taken as energy and emissions savings while calculating the C02 reductions. 4 Reduction of transmission and distribution losses .1 ‘ s 1

4.1 Introduction

Maharashtra has one of the lowest transmission and distribution losses among the states in India. However, as seen from Table 4.1, T&D losses in recent years have been increasing and have been higher than the limit of 15.5 per cent suggested by Electrical Power Research Institute (EPRI) and endorsed by the Rajadhakshya Committee (RCP, 1989). The losses were at a lower level - 14.3 to 14.5 per cent - during 1985-86 and 1987 and it may be possible to improve and bring current losses to these levels. The scope for improvement may exist even if overall system losses are within the acceptable limits. A detailed analysis of losses in the system may be useful in identifying inefficiencies, if any, in the subsystems. In the case of MSEB, deterioration in the efficiency of the T&D system is evident from increased losses due to overloading of transformers, transmission lines, distribution network and increased rural electrification. Investment in the T&D system has not kept pace with increased electricity generation and demand in the system, resulting in the above distortions.

Table 4.1. T&D losses in selected states of India

Year Haryana Uttar Pradesh Tamil Nadu Maharashtra All India

1980-81 22.6 15.6 19.1 16.2 20.6 1985-86 19.8 20.5 18.7 14.5 21.7 1986-87 20.6 20 18.7 14.5 21.5 1987-88 25.4 26.8 18.6 14.3 22.1 1988-89 26.6 27.4 17.7 15.8 22.3 1989-90 29.2 26.1 18.5 17.6 22.9 1990-91 28.2 27.1 17.9 18.3 22.9 1991-92 24.2 25.3 18.4 15.5 22.8 1992-93 25.5 24.1 17.3 16.4 21.8

Source: Current Energy Scene in India, CMIE, June 1994

As can be seen from Table 4.2, the distribution system losses are on the higher side and could be reduced. According to a study carried out by MSEB, about 8,000 out of a total of 100,000 distribution transformers were overloaded. Agricultural consumers were the source of large reactive loads (with power factor (PF) as low as 0.6 to 0.65) due to their failure to install proper capacitors for compensation. It was also observed that at different stages there was scope for upgradation of transmission voltage to the next higher level.

45 Table 4.2. Typical losses in the MSEB system

Level Loss Suggested Upper Limit (%)*

Extra High Voltage (EHV) Transmission 3% 3 to 4% depending on voltage level considered Sub-transmission . 4% 4 to 4.5% Distribution 8.5% to 9% 7%

Total 15.5 to 16% 14 to 15.5%

* By the Rajadhakshya Committee

4.2 Assessment of losses

As seen from Table 4.2, most of the losses occur at the distribution level (i.e 11 kV and below). The losses can be divided into two categories: technical and non-technical losses. Breakup of the Real or Technical losses occur due to the energy dissipated in various components of distribution system. These consist of feeder losses (that vary with load) and transformer losses (that consist of iron and copper losses). The technical losses relate to the physical properties of the conductor and current flow in the circuit. To minimize these losses, an optimally designed T&D system incorporating appropriate technology is required. Commercial or Non-technical losses comprise the losses arising from pilferage of energy, inaccurate meter readings, defective meters, etc.

4.3 Identification of losses

Quantification of existing system losses is the first requirement in an analysis of losses. The difference between the total amount billed to consumers and energy sent out by generating stations gives an estimate of the total losses in the system. This can be used to identify sub systems for detailed study. A typical distribution system along with associated networks can be picked up for detailed analysis.

4.3.1 Steps in identification of losses and loss reduction study

(i) Preparation of database and maps for high tension (HT) and low tension (LT) distribution network. A system map containing information about HT and LT lines, size of conductors/cables and section-wise lengths and location of substations is required for the purpose. This is followed by a detailed survey to find out phase-wise loading of various feeders. For each feeder, information about the number of distribution transformers and their capacities, number of consumers, maximum demand, etc. is also needed. This information is used to identify the overloaded feeders. Therefore, up to-date information on existing distribution system has to be gathered for this purpose.

(ii) Measurement of actual energy losses. This is done for a few representative feeders identified in Step-(i) above. Energy meters are installed at various appropriate

46 locations to measure energy losses in each section of the transmission, sub transmission and distribution system. Measurements required for typical feeders are: (a) Feeder input quantities: voltage, power, power factor, energy. These are measured at the power station or substation switchboard, (b) Distribution Transformer Loads: voltage, current. Distribution of load on a feeder along its length is measured using "clip on" and recording ammeters. This is required since load depends on actual loading of transformers on the feeders and not on their connected capacities, (c) Low Voltage Feeder Distribution: voltage, current. Clip-on instruments are the easiest method of determining the distribution of load within a selected low voltage system.

(iii) Investigation of causes for high losses. Once a high loss area has been identified, reasons for high losses are to be investigated. The factors to be studied for the losses are shown in Figure 4.1. These are: (a) Inadequate conductor size: This leads to overloading of the lines and consequently increases energy losses, (b) Poor power factor: The demand for reactive power from industrial load, households and commercial establishments (due to use of fluorescent tubes and air-conditioners) and agriculture (due to induction motors used with agricultural pumps) decreases the power factor. Reactive power is supplied by the generating units and this overloads the T&D system. It increases energy losses, (c) Low load and demand factor: In some cases, low load factor of a distribution system causes high energy losses (in percentage terms) due to the no load losses (copper and iron losses). The no load losses occur because the distribution system and transformers have to be kept energized all the time. Low demand factor implies over-sizing of the distribution system, which also results in higher losses, (d) Improper location of distribution transformer: If the distribution transformer is far away from the load centre, it requires long HT and LT lines. This may happen due to unplanned extension of lines during electrification. It causes poor voltage regulations and consequently increases energy losses, (e) Poor quality and inadequate maintainance of equipment and lines: Poor quality equipment like transformers, switchgears, switches etc. cause higher energy losses. Such equipment are also prone to failure, causing interruptions in the distribution system. Lack of quality control during construction or inadequate maintenance also increase line losses and make the system unreliable. For example, loose joints, loose connections, improper switch contacts, etc. add to losses, (f) Pilferage of energy.

4.4 Measures for reduction of technical losses

MSEB has a large T&D system and it has to constantly expand to meet the growing needs of the state’s economy. The loss reduction measures for a system like this have to be two fold; short term measures to remove existing distortions that cause higher losses, and long term measures, keeping the future expansion of the system in mind.

47 ENERGY LOSSES

TECHNICAL LOSSES NON-TECHNICAL LOSSES

TRANSFORMER LOSSES FEEDER LOSSES FAULTY METERS

PILFERAGE OVER CAPACITY BAD QUALITY POOR MAINTENANCE

LOW LOAD FACTOR OVERLOADED FEEDER HIGH FEEDER RESISTANCE LOW DEMAND LOW POWER FACTOR UNEVEN DEMAND LOW TRANSMISSION VOLTAGE

HIGH DEMAND

LONG FEEDER LENGTH INADEQUATE CROSS SECTION

NETWORK CONFIGURATION

DISTANCE BETWEEN DIST. TRANS. AND LOAD

Figure 4.1. Losses in transmission and distribution system

4.4.1 Short term measures

The focus of short term measures is to reduce losses in the existing system. Short term measures include:

(i) Reconductoring. First 25 per cent of the length of the HT line is responsible for a major part of the losses. Increased cross-section of this part of the line can reduce losses. While this is also true for LT lines, reallocation of injection points may be more effective in this case.

(ii) Installation of capacitors for power factor improvement. Conductor loading (and hence feeder losses) and voltage drops can be reduced by installing capacitors at the sub stations. For 33 kV lines and above, capacitor installation at the grid substation can be taken up so that operators may switch it on as per requirements. LT and large industrial consumers can be asked to install capacitors in their premises to keep PF within acceptable level. The reactive power planning problem is best addressed locally. Static VAr Compensators (SVCs) can be installed in those areas identified as having high reactive power demand. SVCs can provide continuously varying inductive or capacitive power support.

(iii) Improved load factor. The maximum demand can be reduced by using demand side management techniques. Staggering of loads on outgoing feeders at grid substations can also reduce the maximum demand but this may not be acceptable to consumers. Load factor improvement helps in reduction of constant iron losses in the system.

48 Automatic rostering of rural agricultural loads is an important measure to improve load factor and diversity factor. Such rostering can be done at distribution transformer stations. Some states in India have already implemented this measure. Technologies like ripple control, radio control systems, time clocks, etc. can be used for selective load management in urban areas but this has to be preceded by a proper study and survey and consumer acceptance.

(iv) Reconfiguration of network. Relocation of the distribution transformer near the load centre can also reduce losses. But this is normally possible only when transformer replacement is required. Depending on load density, load decentralization may also be useful. The length of LT lines should be minimized in order to reduce losses. This would require a study of the LT distribution system. Additional substations may have to be added to minimize line lengths for HT and LT systems.

(v) Distribution transformer load monitoring. Load balance between phases can be achieved through load monitoring at distribution transformers. It also would indicate whether the transformer is overloaded or not. Depending on load conditions, transformer rating can be decided. A transfomer which is under-utilized (high rating) also causes higher losses due to high iron loss. At times, it may be possible to reduce losses by reorientation and adjustment of loads on distribution transformers so that their capacities are optimally utilized.

(vi) Upgradation of operating voltage levels. This is possible for HT as well as LT lines. In the case of HT lines, improvements in insulators can allow for upgradation of voltage level, thereby reducing losses. For example, substitution of porcelain insulators by polymer insulators can increase transmission capacity substantially with the existing structure and conductors. A systems study can be made, to identify whether parts of the system are operating with old equipments and at lower voltage than the prevailing level of demand requires. Even one such feeder can account for a majority of losses in the system. Such equipments may need to be replaced.

(vii) Improved operation and maintenance (O&M) practices. O&M practices should be reviewed periodically to identify deficiences. Deficient practices indicate an overall poor approach to the problem of loss reduction.

(viii) Penalty for low power factor. A low power factor surcharge on tariff can be introduced to encourage consumers to improve their power factor. Since improvement in power factor will cost the consumer, the surcharge could be designed in a manner that will provide sufficient incentive to the consumer to improve the power factor.

(ix) Optimal reactive power generation. Optimization of reactive power generations from the generating units can also be helpful in reducing the losses.

4.4.2 Long term measures

Utilities need to study distribution system requirements in the long run in order to minimize losses with changing load demands and other requirements. For utilities like MSEB which have been expanding continuously to meet increased load demands, it is essential to look at

49 long term measures such as those given below, to optimize system operations and reduce losses.

(i) Mapping ofT&D network. This includes information on parameters such as conductor size and length, feeder types, transformer capacities, capacitor locations, etc.

(ii) Load data. Information on load centre-wise demands for real and reactive power over a period of time. Demand forecast for load is also required.

(iii) System studies. Detailed distribution system studies, keeping in view, future load development, are required to be carried out. Computer softwares are now readily available for such system studies of distribution networks. The studies can look into optimum siting for substations, capacitor requirements and locations, optimum routing of lines, load forecasting, etc. The long term possibility of interlinking the substations with high voltage (HV) and extra high voltage (EHV) circuits and grid with optical fibre cables needs to be examined. This will help in controlling an entire system from one control centre (as is prevalent in the developed countries).

4.5 Measures for reduction of commercial/non-technical losses

Although measures like frequent checks and close supervision can reduce pilferage from the customer end, the quality of training and motivation of staff, and remuneration levels of meter readers are important issues in preventing collusion of utility staff with the consumer in pilferage. Measures like proper training programmes to motivate the staff, rewards, etc. can help in changing the attitude and approach of an employee to the job. To check malpractices at the customer’s end the following measures may be helpful: installation of tamper proof meter boxes to check pilferage; surprise raids to check thefts; periodic energy audits for large customers; penalty for pilferage.

4.6 Measures taken by MSEB to reduce T&D losses

It has been mentioned that T&D losses in the MSEB system are low, when compared to losses in other states and at the all-India level. But these have been fluctuating and the trend is for losses to increase over time (Table 4.1). It is also evident from Table 4.2 that losses in the distribution system are higher than the prescribed norms. A study of the MSEB system (see Section 3.7 for details) indicates that even in the transmission system, there is much scope for improvement. Distribution losses of the overall network are not reflected in MSEB data. In Bombay, besides MSEB there are three other utilities that distribute power, viz., Bombay Electric Supply and Transport (BEST), Bombay Suburban Electric Supply (BSES) and Tata Electric Company (TEC). BEST and BSES buy power in bulk from MSEB and TEC and distribute it in their areas. Thus, a substantial part of the distribution system in Bombay (a major consumer of power in Maharashtra) is outside MSEB’s distribution network. The losses in this segment are not accounted for in MSEB’s figures.

50 MSEB has initiated several measures to reduce T&D losses. 11 kV and LT networks have been identified as a thrust area to reduce losses, since the percentage of losses is the highest in these. Consumers are also required to instal capacitors on LT motor loads on their premises. Overloaded distribution transformers have been identified and additional transformers are being provided to reduce overloading. In the case of agricultural loads, where consumers have failed to maintain capacitors (resulting in high reactive loads and low PF between 0.6 and 0.65), MSEB has initiated a scheme to provide switched LT capacitors on transformers on lease basis. The ratio of total lengths of LT lines to 11 kV lines is planned to be reduced during the next five years. It is also planned to restrict the average length of 11 kV feeder to 25 km from the current average of 30 km, and that of 33 kV to 20 km from the present 25 km. New EHV and 33 kV substations will be added with capacitor banks. Wherever possible, the operating voltage will be upgraded from LT to 11 kV, from 11 kV to 33 kV and from 33 kV to EHV. For HT consumers an average PF of 0.9 has been made mandatory with provision of penalty if the PF falls below this. Computer softwares are being used by MSEB to plan optimally the distribution networks within and across districts.

MSEB has identified several actions to deal with non-technical (commercial) losses. These include improving quality of meters and provision of current transformer (CT) operated meters for high loads (> 30 Amp). To eliminate pilferage, mechanisms have been instituted, such as check on faulty meters, scrutiny of abnormal variations in consumption, audit of consumption with meter on feeders, study of specific consumer classes for consumption of electricity and periodic surprise checks. The use of polypropylene film seals on meters has also been introduced to make them tamper proof. For major consumers, steel cubicles for meters are provided. A scheme to award incentives to check theft of energy, and penalty for pilferage, has also been introduced. Losses are expected to be brought to a level of 15 per cent as a result of these measures taken by MSEB.

4.7 MSEB: A study of losses

As already pointed out, the study of losses for a distribution system involves a field study and actual setting up of energy meters and other measuring equipment. Instruments have to be set up at different locations in the distribution system, and such an exercise needs the active involvement of both utility and consumers in the study. Such a field study involving experiments is outside the scope of the present work.

The losses on the HT side (i.e. for EHV transmission) are relatively small and within the limits suggested by experts (RCP, 1989). In this exercise we have analyzed the HT transmission losses based on the data for a typical peak period, to explore further scope for reduction. For this purpose, we study the MSEB transmission system at 400 kV, 220 kV, 132 kV and 100 kV levels. Since the data chosen for analysis is based on a snapshot picture of a typical peak period, the interpretation should be seen in this context. We had access only to this limited data.

51 4.7.1 MSEB transmission and distribution network

In the MSEB .system, bulk power is transmitted through long 400 kV lines from the large pit- head thermal power stations situated in eastern Maharashtra (Chandrapur TPS, Koradi TPS, Parli TPS and Khaperkheda TPS) to the load centres on the western side (Bombay, Pune, etc).

MSEB transmits power at 400 kV, 220 kV, 132 kV and 100 kV voltage levels. The sub transmission level voltages are 66 kV and 33 kV while distribution is generally at 11 kV and 400 Volts. Due to unavailability of data, even for the transmission system the study has been restricted up to 100 kV voltage level.

The peak load in the MSEB system is about 6,890 MW and 4,498 MVAr (1994), which is supplied at different transmission and sub-transmission levels. The bulk of the load (3,568 MW, 2,486 MVAr) is on the 220 kV voltage level which caters to the HT industries. The break up of the load drawn from MSEB at different voltage levels is shown in Table 4.3.

Table 4.3. Voltage level-wise breakup of loads in MSEB system

Peak Load Peak Reactive Load No. of Buses

400 kV level 9 220 kV level 3,568 MW 2,486 MVAr 52 132 kV level 1,379 MW 963 MVAr 16 100 kV level 1,943 MW 1,049 MVAr 23

Total 6,890 MW 4,498 MVAr 101

Source: Based on information collected from MSEB, Bombay

4.7.2 Load flow study

Load flow calculations provide power flows and voltages subject to a regulating capability of generators, condensers, etc. and net interchange between individual operating systems. This information is essential for the continuous evaluation of the current performance of the transmission system. It is also used for analyzing the effectiveness of alternative plans for system expansion to meet increased load demand.

Load flow studies have been carried out for the MSEB transmission system up to 100 kV level. From the studies, substations have been identified where the voltage drops are significantly high. These high voltage drops can be attributed to high reactive load at the substation bus and inadequate reactive power compensation at the substation transformer.

These factors cause voltage drops and hence increase the losses in the transmission system. Specific studies at different voltage levels are detailed below.

52 400 kV level

In MSEB’s transmission system, 400 kV is the highest voltage level. There are sixteen 400 kV lines linking the nine 400 kV substations within the state. These buses do not supply any load. In spite of this, load flow analysis revealed that there were voltage drops of the order of 15-25 kV over the 400 kV lines. This may be due to large power transfers (both real and reactive) and inadequate reactive power compensation at the receiving end sub-stations.

The 400 kV buses are listed in Table 4.4 along with voltage condition during the typical peak load condition of the system. The status of reactive power compensation at these substation buses is also given. As Table 4.4 indicates, no compensation has been provided in the case of some buses (Kalwa, Babhaleswar and Padghe), resulting in voltage drop of the order of 10-14 kV. In other cases, compensators were found to be inadequate for the bulk reactive power transmissions, leading to significant voltage drops of the order of 20 kV.

Table 4.4. 400 kV sub-station buses

400 kV Buses Actual Voltage Compensation Kalwa 386.9 kV None Lonikand 382.8 kV Inadequate Karad 377.7 kV Inadequate Babhaleswar 392.6 None Padghe 390.3 None Parli 396.92 Adequate Chandrapur 408.97 Adequate Koradi 400.81 Adequate Bhusawal 396.88 Adequate

Source: IGIDR Study

220 kV level

In MSEB’s transmission system, the 220 kV voltage level accounts for the highest loading in the system. However, there are a number of 220 kV substations with low power factors due to large reactive power loads. This leads to losses in this network. From Table 4.5 it is clear that although the reactive power demand is not significant, there is a considerable voltage drop at some substations. This is because of large power transfers that also require compensation. Due to poor voltage profile, loadability of the lines also decreases.

53 Table 4.5. 220 kV buses with low power factor loads

220 kV Bus Load (MW) Reactive Load (MVAr) Power Factor Voltage (kV) Trombay 25 20 0.781 215 Baramati 18 14 0.789 212.1 Lonavala 137 111 0.777 212.5 Koyna 18 15 0.768 220.25 Parbhani 45 36 0.781 210.7 Karad 135 106 0.787 219.1 Sholapur 211 171 0.777 212.7 Wardha 54 45 0.768 225.2

Source: IGIDR Study

Table 4.6. 220 kv buses with low voltage conditions

220 kV Bus Load (MW) Reactive Load (MVAr) Power Factor Voltage (kV) Compensation Amravati 45 9 0.981 206.18 Inadequate Bhandup 0 0 - 203.56 None

Source: IGIDR Study

132 kV level

A similar analysis to the one described above, has been carried out for 132 kV and 100 kV sub-stations to identify the load centres where the voltage drop was significantly high or compensation was not adequate for loads having a low power factor. As seen from Table 4.7, there are a number of 132 kV substations where the power factor is very low. This is due to large reactive power loads at these buses. This is one of the major causes for high loss in the network and can be suitably rectified. It can also be seen that there are a few substations where, although the reactive power demand is not significantly high, there is a considerable voltage drop.

Table 4.7. 132 kV buses with low power factor loads

132 kV Bus Load (MW) Reactive Load (MVAr) Power Factor Voltage (kV) Malkapur 50 39 0.789 124.9 Nagpur 1 56 41 0.807 122.69 Bhusawal 165 123 0.802 133.18 Ambazari 126 93 0.805 124.25 Ahmednagar 101 75 0.803 129.76 Bhabaleswar 200 150 0.8 130.77 Nagpur2 56 41 0.807 121.37 Beed 27 20 0.804 131.29

Source: IGIDR Study

54 Table 4.8. 132 kV buses with low voltage conditions

132 kV Buses Load Reactive Load Power Factor Voltage Compensation (MW) (MVAr) (kV)

Amravati 174 119 0.825 121.2 Inadequate Hingmi 46 32 0.821 121.9 None Besal 46 32 0.821 120.45 None

Source: IGIDR Study

100 kV level

Table 4.9 lists those buses at the 100 kV substation level where the loads have a high reactive power component. It is to be noted that since the voltage level is low at this stage, the magnitude of losses increases here for the same reactive power load being met.

Table 4.9. Buses with low power factor loads

100 kV Buses Load Reactive Load Power Factor Voltage (MW) (MVAr) (kV)

Kalyan 80 65 0.776 96.7 Borivili 290 215 0.803 96.2 BMC1 5 5 0.707 98 Cam IB 70 73 0.692 99.6

Source: IGIDR Study

55 5 Demand side management options for high tension industries in Maharastra

5.1 Introduction

The demand side management (DSM) part of this study is based on a recently concluded IGIDR project on DSM (Parikh, Reddy and Banerjee, 1994) in which an implementable plan for high tension (HT) industries in Maharashtra has been suggested. DSM helps in saving energy and demand at the consumer ’s end. This reduces the need for generation of energy. The reduction in generation is more than the saved energy, considering that T&D losses (for the energy saved) are also avoided. In addition to energy and demand savings, DSM programmes have other benefits, viz., a shorter gestation period of one to two years as compared to four years or more for power plants. DSM also reduces the burden on the transport system since reducing generation means less fuel (say coal) is required to be transported over long distances. Thus expenditure on infrastructure like coal mining, transport, land for power plant etc. are avoided. This results in a better environment overall, since the same amount of useful energy is provided with fewer inputs and hence less emissions.

The HT industrial sector in Maharashtra consumed 31% of electricity (11,600 MU) during 1992-93 with average consumption per consumer being 15 MU. It also accounted for a peak demand of 2,600 MW (38%) out of the 6,820 MW system peak demand of MSEB. DSM can be more effective in the HT industry sector since the programme managers have to deal with only a few consumers with large potential for savings.

5.2 Consumption pattern in HT industries

In the HT industrial sector, electricity is used in many applications, viz., motive power, electric heating, air-conditioning, lighting, etc. In a survey of HT industries conducted by IGIDR (Parikh et al., 1992) the shares of different type of loads (end uses) in different categories of industries were studied. This revealed that, in terms of connected load the share of motors was the highest (48.5%) followed by melting (16.0%), electric heating (13.4%), air compressors (9.4%), air conditioning (3.8%) and lighting (3.7%). Industry-wise details are given in Table 5.1.

Corresponding energy consumption in different categories of industries is given in Table 5.2. The results indicate that motor with 47.7% is the main end-use followed by melting with 16.30% and electric heating with 10.15%, air compressors with 9.8%, air conditioning with 5.62% and lighting 4.89%.

56 Table 5.1. Electricity load distribution by categoiy and end-use (1990-91)

End-use Connected load by industrial categoiy (MW) Iron & Steel Chemical Textile Engg. Paper Pharmaceutical Non-Ferrous Miscellaneous Total Motor/Pump 200 (34.3) 126 (58) 114 (55) 98 (39.9) 84 (84.3) 36 (43.4) 11 (65) 783 (55) 1342 (48.6) Melting/Smelting 310(53.3) 0 2(1.2) 3 (14.4) 0 0 0 95 (6.7) 443 (16.1) Electric Heating 31 (5.4) 11 (5.4) 16(8) 41 (16.6) 0 6 (6.8) 4 (23.6) 259 (18.2) 369 (13.4) Compressor 13 (2.3) 37(16.9) 10 (4.6) 28 (11.5) 0 14 (16.6) 0 159(11.2) 261 (9.4) Lighting 7(1.3) ■ 6 (2.6) 11 (5.1) 12 (5.6) 4(4) 3 (3.5) 1 (6.2) 58(4.1) 104 (3.8) Air-Conditioning 2 (0.4) 20 (9.3) 39(18.8) 11 (4.3) 0 16(19.5) 0 18(1.3) 107 (3.9) Others 17 (3) 17 (7.8) 16 (7.5) 19 (7.8) 13 (11.8) 8 (10.4) 1 (5.3) 49 (3.4) 138 (5) Total 583 (20.4) 217 (7.6) 207 (7.3) 246 (8.6) 100 (3.5) 82 (2.9) 17 (0.6) 1422 (49.7) 2764 (100)

Note: Figures in parentheses represent percentages

Table 5.2. Consumption by end use and category-wise (Maharashtra)

End-use Electricity consumption (MU) Iron & Steel Chcrn Textile Engg Cement Paper Pharma Non-Fe Forth Misc. Total Motor/pump/fan 721 (31) 936 (55) 647 (56) 478 (38.6) 290 (71.6) 262 (75.6) 48 (36) 46 (66.6) 103 (78.5) 1110(49) 4641 (47.6) Melting 1179 (51) 30 (1.7) 22(1.9) 187 (15.1) 0 0 0 0 0 172 (7.5) 1589 (16) Electric heating 125 (5.5) 100 (5.9) 82 (7) 214(17.3) 0 0 5 (3.8) 14 (20.7) 1 (0.7) 449 (19.6) 990 (10) Air Compressor 73 (3) 275 (16) 65 (5.6) 174(14) 49(12) 35(10) 17(13) 0 10 (7.7) 260 (11) 959 (9.8) AC/Rcfrigcration 37(1.6) 170 (10) 201 (17.4) 52(4) 14 (3.5) 0 44 (33) 0 0 31 (1.4) 549 (5.6) Lighting 53 (2) 108 (6.4) 82 (7) 77 (6) 27 (6.6) 15(4) 6 (4.7) 5 (7.4) 5 (3.9) 100 (4.4) 478 (4.9) Others 106 (4.6) 85 (5) 60 (5) 56 (4.6) 25 (6) 35 (10) 12(9) 4(5) 12(9) 146 (6) 540 (5.5) Total 2293 (23.5) 1703 (19) 1160(11.9) 1239 (12.7) 405 (4) 347 (3.6) 133 (1.4) 69 (0.7) 131 (1.3) 2267 (23) 9746 (100)

Note: Figures in parentheses represent percentages 5.3 DSM options

DSM options were identified on the basis of the HT industry survey and discussions with energy consultants, equipment manufacturers and consumers.

The benefit-cost analysis for each DSM option has been worked out for the consumer. The potential market for a particular DSM option was taken based on the feedback obtained from energy auditors and surveys (Devki, 1990), and the following DSM options were identified: energy efficient motors (EEM); variable speed drives (VSD); good housekeeping practices (GHK); waste heat driven vapour absorption systems (VARS); time of day tariffs (TOD); improved electric arc furnaces (EAF); high pressure sodium vapour lamps (HPSV); compact fluorescent lamps (CEL); electronic ballasts (ELB); high efficiency fans and pumps (PUMPFAN); improved power factor (PF); industrial cogeneration (COGEN)

For each of the options, the following input data have been used:

5.3.1 Option characteristics

Option characteristics include capital, installation, operation and maintenance costs, efficiency, useful lifetime, current market share (percentage of industries currently using the option) and peak coincidence factor (the fraction of the utility peak time the appliance is used). Technology characteristics have been taken from manufacturers ’ catalogues.

5.3.2 Market segment profiles

The market size and growth rates are required as input data. The market size has been obtained from the IGIDR-HT survey of end-use analysis in HT industries. It is assumed that the HT industries ’ growth rate of electricity consumption is 7% per year in line with past trend.

5.3.3 Utility characteristics

The database includes information on discount rate, transmission and distribution loss factor, avoided capacity and energy costs, sales forecast and number of consumers. Since this part of the study is based on the IGIDR DSM study (Parikh, Reddy and Banerjee, 1994), it is important to note that, charges for the industrial sector @Rs. 2/kWh and Rs. 100/kW of demand have been used (1992-93 values). A 10% escalation in nominal rates every year is assumed. This is used to determine the payback periods.

5.4 Formulation of DSM programmes

5.4.1 What is a DSM programme?

DSM involves intervention by the implementing agency (utility or any other organization) to achieve consumer load modifications. A DSM programme needs to be launched with a suitable financial package catering to a particular option. A set of DSM options with financial

58 incentives for each is called a DSM programme. There is a difference in the availability of capital (and interest rates) for the implementing agency and the consumer. This is reflected in the difference in discount rates. The discount rate for the implementing agency is taken as 14% (expected long term interest rate for the agency) while the consumer discount rate is taken as 25% (corresponding to a payback period between 3 to 4 years). For industrial consumers, DSM/energy conservation schemes compete with investments in augmenting production for their limited capital resources.

5.4.2 Programme costs

Programme costs are developmental costs are incurred in the first year of the programme, in addition to the recurring costs for each year of the programme. Since consumer interest rates are 25%, as against 14% for the implementing agency due to the availability of soft loans, it is necessary to offer an appropriate financial package along with every DSM option. The financial incentives could include initial capital subsidies, low interest credit schemes, accelerated depreciation and tax rebates.

Financial incentives can be channelized through energy service companies, SEBs, financial institutions or energy development and management agencies at the state and central levels. For each DSM option, an initial incentive has been proposed. It is proposed that a portion of the initial capital cost is to be provided on a cost sharing basis. This one-time first year cost sharing is necessary to make the consumer ’s simple payback period acceptable. The extent of cost sharing values proposed in this work are illustrative and could be modified, if necessary.

5.4.3 Market diffusion

The maximum penetration of a DSM option depends on the level of subsidy and also on the implied discount rate to the consumer. To measure the annual market penetration of a DSM option, a diffusion curve has been used. An empirical logit function is used to track market adoption over time.

There is a chance of consumers not participating in the programme at any time (even in the long run, viz., a 20 year period) for a number of reasons. For the DSM options it is assumed that 20% of the consumers are unwilling to switcover to efficient appliances even after 20 years (ie an unwillingness of 20%).

5.5 COMPASS model

COMPASS software analyzes DSM and strategic marketing options. The model takes into account the following factors: load structure by category; electricity consumption by each load category; utility tariff structure; utility avoided costs; DSM options along with costs of base as well as the suggested DSM technologies; market segment characteristics; market penetration (diffusion) characteristics. This model was used for the analysis.

59 5.6 DSM option analysis

The various DSM options have been analyzed and a five-year DSM plan has been prepared. The DSM study (Parikh et al., 1994) results provide the annual implementable targets of a number of adoptions, and energy and demand savings for each option over a period of five years (1994-98). Since the study by Parikh et al. (1994) considered the five year period 1993- 97, the results were modified to reckon the period from 1994.

For each DSM option, an initial incentive has been proposed in which a portion of the capital cost is to be provided by an agency other than the consumer on a cost-sharing basis.

The study considers the total market (ie all the consumers of a particular appliance) including the replacement market (ie. consumer segment in which appliance replacement is taking place as the old appliance has completed its useful life). However, for energy efficient motors and electronic ballasts, only the replacement market has been considered because of the general reluctance to change working motors/ ballasts for small efficiency gains. For the other DSM options the total market is considered. After fixing the potential market size, the long range market share of DSM options is determined.

For each option, techno-economic characteristics, industry-specific use and assumptions concerning cost-sharing and expected diffusion are considered.

5.6.1 Energy efficient motors

Electric motors are used in industries to drive pumps, fans, compressors, machine tools and a wide variety of other process equipment. These account for 60-70% of the industrial electricity consumption. EEMs whose efficiency is 3 to 5% higher than that of conventional motors (owing to better design and materials), are available. The annual energy requirement of motors has been computed assuming full load operation for 4,000 hours. A peak coincidence factor of 80% has been assumed. The life of motors has been taken as 15 years (Box 5.1).

The total connected load for motors in HT industries in 1989-90 was 1,877 MW (66% of the total). The connected load for motors/fans/pumps was 1,474 MW, for air compressors its was 271 MW and for refrigeration the load was 132 MW.

The number of motors in each category has been obtained by considering 7% annual growth rate from 1989-90 values. Table 5.3 shows the annual targets for DSM programme for EEMs. It is seen that 14.3 MW of peak demand can be saved by 1998. This is equivalent to a cost saving of Rs. 9,000/kW. The total cost of saved demand is Rs. 17,600/kW. The cost of saved energy is Rs. 0.63/kWh: A total of 44,960 EEMs have to be installed during the plan period.

60 Motor ratings considered: 1-5 hp 5-10 hp 10-15 hp 15-20 hp 20-50 hp > 50 hp

Connected load = 1,877 MW Cost of EEM = 30% higher than standard motor Life = 15 Years Hours of operation = 4,000 Hours No. of motors = 0.27 Million Cost sharing = 50% of incremental cost Peak coincidence factor = 80% Unwillingness = 20% Simple payback with programme = 0.5 to 2.4 years Simple payback without programme = 1.0 to 4.8 years Cost of saved energy = 0.63 Rs/kWh Programme cost = 9,000 Rs/kW

Box 5.1. Energy efficient motors

Table 5.3. Annual DSM programme targets forenergy efficient motors

Year Demand savings Energy savings Total adoptions Programme cost (MW) (MU) (no.) (Rs.million)

1994 1.47 7.34 3110 11.22 1995 3.13 15.65 5140 19.81 1996 5.64 28.21 7770 32.20 1997 9.27 46.36 11230 50.04 1998 14.3 71.7 15710 75.3

Total 14.3 169.26 44960 188.57

Source: Parikh, Reddy and Banerjee (1994)

5.6.2 Variable speed drive

Fluids driven by pumps, fans and blowers are usually regulated by throttling. This is an inefficient method of control and results in significant energy losses. A more efficient method is to control the speed of the motor using a VSD. VSDs permit continuous regulation of motor speed leading to substantial energy savings, particularly during partial load operations. VSDs have significant scope in paper, chemical, fertilizer, pharmaceutical and cement industries. The life of VSDs has been taken as 10 years. In the present analysis only motors with ratings above 10 hp are considered (Box 5.2).

61 Eligibility = 25% (> 10 hp drive) Cost of VSD = 11,000 Rs./kW Additional cost for existing units = 10% Maintenance cost = 1% of Total Cost Life of VSD = 15 Years Hours of operation = 6,000 per year Cost sharing = 25% Peak coincidence factor = 80% Unwillingness = 20% Five year target (nos.) = 6,700 Savings at 90% loading Energy = 30% Demand = 20% Simple payback with programme = 2 to 2.1 years Simple payback without programme = 2.6 to 2.8 years Cost of saved energy = 1.05 Rs./kWh Programme cost = 10,200 Rs./kW

Box 5.2. Variable speed drives

Table 5.4 shows the annual DSM targets for VSDs. It is seen that the peak demand savings by adoption of VSDs in the plan period is 54.1 MW. A total of 8870 VSDs are adopted during this period. The cost of demand saved for the utility is Rs. 10,200/kW. The total energy savings from VSDs is 1260.74 MU and the cost of saved energy is Rs. 1.05/kWh.

Table 5.4. Annual DSM programme targets for VSDs

Year Demand savings Energy savings Total adoptions Programme cost (MW) (MU) (no.) (Rs.million) 1994 9.26 82.41 920 11.0 1995 15.91 141.65 1190 19.77 1996 24.95 222.08 1610 32.67 1997 37.42 333.1 2210 52.13 1998 54.10 481.5 2940 79.9 Total 54.10 1260.74 8870 195.47

5.6.3 Good housekeeping practices (GHK)

Good housekeeping practices include measures like reducing leakage of compressed air, proper sizing of motors, improved daylighting, reducing chilled water usage, improved monitoring and control. Since they are energy intensive, HT industries are already reasonably aware of energy efficient practices. To bring further savings on industrial premises, good housekeeping on a sustained basis would require monitoring and management. Above all, it requires an energy waste avoidance culture.

62 The number of HT industries is taken as 6,200 (1992-93 figures) with an annual energy consumption of 10,360 MU and demand (during the peak period) of 2,500 MW. This is equivalent to an average energy consumption of 1,670,000 kWh/year and a peak demand of 400 kW per factory. A DSM programme for improved housekeeping is assumed to save 5% of the energy and power demand in the adopting industry. For each adopting industry an initial amount of Rs. 0.2 million is to be spent on additional monitoring/testing equipment and energy audits. Fifty per cent of the initial cost (Rs. 0.1 million) is to be given by the implementing agency. It is assumed that the adopting industry will incur an annual expenditure of Rs. 50,000 to maintain GHK. (It must be mentioned that these figures are for the average HT industry with a peak demand of 400 kW. For industries with different loads, the amounts can be proportionately adjusted). The payback period for the adopting industry, in the absence of a programme, is 1.4 years while it is 0.7 years with GHK (Box 5.3).

Maximum industry demand = 2,500 MW Average energy consumption = 1,670 MWh/year Average power factor = 0.9 Initial cost = Rs. 0.2 Million Annual expenditure (recurring) = Rs. 50,000 Saving from GHK = 5% of total energy and demand Cost sharing = 50% of incremental cost Unwillingness = 20% Simple payback with programme = 0.7 years Simple payback without programme = 1.4 years Cost of Saved energy = 0.86 Rs./kWh Programme cost = 3,800 Rs./kW

Box 5.3. Good housekeeping practices

Table 5.5. Annual DSM programme targets for good housekeeping

Year Demand savings Energy savings No. of Programme cost (MW) (MU) adoptions (Rs.million)

1994 13.63 56.52 319 35.1 1995 23.49 97.41 416 49.22 1996 36.82 152.65 562 71.55 1997 55.19 228.83 775 106.25 1998 80 331 1072 153.3

Total 80.0 906.41 3144 415.42

63 Table 5.5 shows the annual targets for this DSM option. During the five year period a demand saving of about 80 MW and energy savings of 906.41 MU can be achieved. The cost is equivalent to a cost of saved demand (for the utility) of Rs. 3,800/kW. If participant costs are included, the total cost of saved demand is Rs. 11,900/kW. The cost of saved energy is Rs. 0.86/kWh.

5.6.4 Waste heat driven vapour absorption refrigeration systems (VARS)

Conventional vapour compression refrigeration systems account for almost the entire air conditioning and cooling (refrigeration) load. Instead of compression refrigeration systems it is possible to use VARS driven by waste heat or surplus steam.

Estimated from the IGIDR-HT industry survey, the total connected cooling load of Maharashtra in 1989-90 was 132MW. This amounts to. a connected load of 162 MW in 1992- 93 which is equivalent to 162,000 TR (tonnes of refrigeration). Absorption chillers have potential applications in chemicals, synthetics, pharmaceuticals and food industries. It is assumed that 25% of the cooling load is suitable for VARS application. The chillers are assumed to operate for 5,000 hours/year and have a peak coincidence factor of 70%. The costs of the conventional system and VARS have been obtained as Rs. 12,000 and Rs. 25,000/tonne of refrigeration from manufacturers. The average electricity consumption for a process chiller is about 1 kWh/TR while for a VARS it is about 0.1 kWh/TR. The life of both systems is taken as 20 years and the maintenance costs of both systems are assumed to be the same although conventional system costs can be much higher. For existing industries an additional installation cost of 10% has been considered. Thirty percent of the initial capital cost is to be provided by the implementing agency. For new installations the payback period without the programme is 1.3 years and with the programme is 0.6 years. For existing installations when the entire cost of the system is an additional investment the payback period without a programme is 2.7 years. This reduces to 1.9 years with the programme. 20% of the eligible market is assumed to be unwilling (Box 5.4). Table 5.6 shows the annual targets for this DSM option.

During the five year plan period a demand saving of about 16.2 MW can be achieved. The number of VARS to be installed is 203 (of 100 TR each). The cost of demand saved for the utility is Rs. 10,600/kW. The total cost of demand saved is Rs. 28,000/kW. The energy savings in the terminal year of the plan is 301.29 MU and the cost of saved energy is Rs. 0.64/kWh.

5.6.5 Improved electric arc furnaces (EAF)

In Maharashtra the iron and steel sector is the largest industrial consumer of electricity. This is mainly accounted for by steel foundries and mini-steel plants. EAF can be retrofitted with technologies like scrap preheating, oxyfuel burners, bottom tapping, computerised control and automation.

Base unit of a furnace with a throughput of 10 tonnes is considered. Retrofit cost of Rs. 5 Million/fumace and savings of 30% are assumed (Nadel et al., 1991).

64 Connected load = 162 MW Connected load = 162,000 TR Electricity consumption for process chiller = 1 kWh/TR Electricity consumption for VARS = 0.1 kWh/TR Cost of conventional system = Rs. 12,000 Cost of Waste heat driven system Rs. 25,000 Life of VARS 20 years Hours of operation (per year) = 5,000 Cost sharing (% of incremental cost) = 30 Peak coincidence factor = 70% Unwillingness = 20% Five year target (nos.) = 42 Simple payback period with programme (years) = 0.6 Simple payback period without programme (years) = 1.3 Cost of saved energy (RsVkWh) = 0.64 Programme cost (Rs./kW) = 10,600

Box 5.4. Vapour absorption refrigeration systems

Table 5.6. Annual DSM programme targets for waste heat driven VARS

Year Demand savings Energy savings Total adoptions Programme cost (MW) (MU) (Rs.million) 1994 2.67 19.06 20 18.2 1995 4.67 33.35 27 26.3 1996 7.41 52.94 37 38.1 1997 11.19 79.94 51 56.1 1998 16.2 116.0 68 80.1

Total 16.2 301.29 203 218.8

The maximum demand of mini-steel plants in the MSEB region added up to 446 MV A in 1989-90. 70% of this load is for melting. This results in a demand of 312 MVA for melting which is equivalent to a demand of 382 MV A in 1992-93. The peak demand in EAFs is about 400 kVA/ton. This implies that there are about 96 arc furnaces with throughput of 10 T in 1992-93. An average electricity consumption of 800 kWh/ton and a tap-to-tap time of 200 minutes is considered. For a 10 T furnace, the peak demand is 4 MVA. Considering a power factor of 0.9 the peak demand is 3.6 MW. A peak coincidence factor of 50% is assumed. For existing units an additional retrofit cost of Rs. 0.5 Million/unit (10% of the capital cost) is considered. 80% of the EAFs are eligible. 20% of the eligible market is assumed to be unwilling. 25% of the capital cost is to be borne by the implementing agency (Box 5.5).

65 Retrofitting base unit of a furnace with a throughput of 10 tons:

Cost of retrofitting = Rs. 5 Million Additional cost for existing unit = Rs. 0.5 Million Cost sharing = 25% Hours of operation = 5,000 Peak coincidence factor = 50% Electricity consumption = 800 kWh/ton Savings = 30% Peak demand = 400 kVA/ton No. of arc furnaces = 96 Tap-to-tap time = 200 minutes Power factor = 0.9 Peak demand = 4 MVA Unwillingness = 20% Simple payback with programme (years) New = 0.5; Existing = 0.6 Simple payback without programme (years) New = 0.7; Existing = 0.8 Cost of saved energy = 0.2 RsVkWh Programme cost = 2,000 Rs./kW

Box 5.5. Improved electric arc furnaces

For new units, payback period without the programme is 0.7 years and with the programme is 0.5 years. For existing units the payback period without the programme is 0.8 years and with the programme is 0.6 years. Table 5.7 shows the annual targets for the improved EAF programme.

Table 5.7 Annual DSM programme targets for improved EAF

Year Demand savings Energy savings Total adoptions Programme cost (MW) (MU) (Rs.million) 1994 3.81 20.33 3 4.78 1995 7.62 40.66 6 9.68 1996 11.44 60.99 6 10.46 1997 17.78 94.87 10 18.43 1998 26.0 139.0 12 25.8 Total 26.0 355.85 37 69.15

For the 37 furnaces, the demand reduction in the plan period is about 26 MW. The cost of demand saved to the utility is Rs. 2,000/kW. This is equivalent to a total cost of demand saving of Rs. 7,500/kW. Improved electric arc furnaces result in energy savings of 355.85 MU in the entire plan period and the cost of saved energy is Rs. 0.20/kWh.

66 5.6.6 Time-of-day tariffs (TOD)

There is a wide variation in the MSES system demand over the daily load cycle. On a typical day the load varied from 4590 to 6200 MW. The peak occurs during 18 to 21 hours, the partial peak extends from 7 to 18 hours and from 21 to 23 hours. Off-peak duration is from 23 hours to 7 hours. If peaking plants are built, they remain idle for the remaining periods and do not earn return during these hours. Hence, the costs of this option to reduce the peak load should be examined first before building peaking plants. This could be done by shifting some of the peak load to other periods. Load levelling would result in improved capacity utilisation. Load levelling or peak shifting could be promoted by the use of tariff related options like time-of-use tariffs. However, care should be taken to ensure that such tariffs do not shift the system peak to some other hours without significantly reducing it.

This DSM option is different from other options since it involves a differential tariff structure. Instead of a flat energy charge of Rs. 2/kWh (MSEB tariff for HT industries) the proposed energy charges are Rs. 3/kWh during peak time, Rs. 2/kWh during partial peak and Rs. 1.50/kWh during off-peak hours. The demand charge remains constant at Rs. 100/kW. While Rs. 3/kWh at peak hours may be approximately the long range marginal cost, Rs. 1,50/kWh at off-peak hours which covers much more than the operating costs, could be further lowered. In case of no action, proposed structure is revenue neutral to consumers with continuous loads. It is revenue enhancing for the utility for those who have two shifts. Many other price structures are possible. To illustrate the benefits of time-of-day tariffs, we consider the above tariff structure (Box 5.6).

Peak hours = 18:00 to 21:00 Partial peak hours = 7:00 to 18:00 and 21:00 to 23:00 Off-peak hours = 23:00 to 7:00 Flat energy charge = 2 Rs./kWh Peak energy charge = 3 RsVkWh Partial peak energy charge = 2 Rs./kWh Off-peak energy charge = 1.5 Rs./kWh Cost of setting up cell = Rs. 2 Million Operating and maintanance costs = Rs. 0.9 Million/annum Cost of "Time-of-use" meter = Rs. 70,000 Cost of demand controller = Rs. 20,000 Initital subsidy = 50% Peak demand reduction = 10% Unwillingness = 20% Cost of saved demand = 1,700 Rs./kW

Box 5.6. Time-of-day tariff

67 It is assumed that an initial subsidy of Rs. 90,000 will be paid by the implementing agency to the adopting industrial unit to cover the costs of a time-of-use meter (Rs. 70,000) and 50% of the cost of a demand controller (Rs. 20,000). For this study, a 10% peak demand reduction is considered for the adopting industrial units which is only about 20-30% of total users. Shifting 10% of the peak demand to off-peak hours results in an average annual bill saving of Rs. 86,000 for the adopting industry. Even if the industry were to bear the total cost of the time-of-day meter and the demand controller the payback period would be 1.3 years. The payback period with the programme is 0.2 years.

Table 5.8 shows the results for the TOD tariff programme. It is seen that 160 MW of demand savings in the plan period is possible. The cost of saved demand for the utility is Rs. 1,700/kW. The total cost of saved demand is Rs. 2,100/kW. Only 27% of the HT industries were assumed to adopt the option in the plan period.

Table 5.8. Annual DSM programme targets for TOD tariff

Year Demand savings Energy savings Total adoptions Programme cost (MW) (MU) (no.) (Rs.million)

1994 27.26 - 319 31.98 1995 46.99 - 416 44.72 1996 73.63 - 562 64.85 1997 110.37 - 775 96.12 1998 160.0 - 1072 138.5 Total 160.0 3144 376.17

5.6.7 Replacement of 250 W high pressure mercury vapour (HPMV) lamps by 150 W high pressure sodium vapour lamps

A 150 W HPMV lamp has the same lumen output as a 150W HPSV lamp (13,500 lumens). These are used for lighting industrial shop floors or street lighting. The HPMV lamps have a power consumption of 272 W, life of 5000 hours and a cost of Rs. 500. The HPSV lamps have a power consumption of 172 W, life of 15,000 hours and a cost of Rs. 930. The life of ballast (control gear) is taken as 10 years and its cost for HPMV is taken as Rs. 675 while that for HPSV as Rs. 600. A peak coincidence factor of 80% and 4,000 hours of operation is assumed. The total lighting connected load is estimated, from the IGIDR-HT survey, to be 111 MW in 1989-90. From this, the connected load in 1992-93 is obtained as 136 MW. Of this 13.6% accounts for HPMV and 9.1% HPSV (Nadel and Kothari, 1991). The total market is 157,000 lamps of which the current market share of HPSV lamps is 53%.

It is assumed that 80% of the market is eligible for HPSV (in some cases the poor colour rendering ability may rule out HPSV). Even in the absence of a programme there is a significant adoption of HPSV lamps by the market. We assume that 10% of the market is unwilling in both the programme and no-programme cases. In the programme, 25% of the cost of the ballast will be borne by the implementing agency. In the no-programme case we assume that the long run market share will be 80% of the eligible market. In this DSM programme we have to consider the free riders effect, i.e., industries who would have opted

68 for HPSV anyway will also put claims on funds from the programme. The number of adoptions is used to calculate the savings. The programme cost includes the subsidy given to the free riders. This increases the cost of this DSM option (Box 5.7).

Life of HPSV (hours) = 15,000 Life of HPMV (hours) = 5,000 Out put (lumens) = 13,500 Consumption by HPMV 272 W/unit Consumption by HPSV 172 W/unit Hours of operation (per year) = 4,000 Total market = 83,000 Peak coincidence factor = 80% Cost of HPMV Rs. 5,000 Cost of ballast Rs. 675 Cost of HPSV Rs. 930 Cost of ballast Rs. 600 Life of ballst (control gear) 10 years Five year target (nos.) = 54,000 Simple payback period with programme (years) = 0.5 Simple payback period without programme (years) = 0.6 Cost of saved energy (RsVkWh) = -0.10 Programme cost (Rs./kW) = 6,500

Box 5.7. High pressure sodium vapour lamps

Table 5.9 shows the annual targets for this DSM programme. It is seen that there is a net demand saving of 1.6 MW and the number total adoptions in the programme is 61990 ballasts. The cost of saved demand for the utility is Rs. 6,500/kW. The total cost of saved demand is Rs. 9,700/kW.

Table 5.9. Annual DSM programme targets for replacing HPMV by HPSV

Year Demand savings Energy savings Total adoptions Programme cost (MW) (MU) (Rs.million) 1994 0.62 3.12 8160 1.59 1995 0.93 4.67 10830 2.25 1996 1.22 6.09 12840 2.86 1997 1.44 7.2 13260 3.17 1998 1.6 8 16900 3.12 Total 1.6 29.08 61990 12.99

Due to the difference in the lives of the bulbs, (a single bulb HPSV has a life equivalent to three HPMV bulbs) over the life of a ballast the difference in the annual cost (bulb replacement) pays for the initial cost of switching to HPSV. Hence, there is no net initial

69 cost when the life time of the HPSV ballast is taken into consideration. The cost of saved energy is Rs. 0.10/kWh.

5.6.8 Replacement of incandescents by compact fluorescent lamps (CFL)

Incandescent bulbs are commonly used in domestic and commercial sectors. Though incandescents account for only about 4% of the industrial lighting, it may be worthwhile to replace them by CFLs in view of energy savings to the extent of 75%. New CFLs last about eight to ten times longer than incandescents and are four times as efficacious. An incandescent lamp with a rating of 60 W has an output of 700 lumens, a life of 1,000 hours and is priced at Rs. 9.60 (1992-93 values). A 11 W CFL has an output of 900 lumens, a life of 8,000 hours and is priced at Rs. 200. The auxiliary consumption of the ballast is 3 W. The cost of the ballast is Rs. 150/- and the life of the ballast is 10 years. The payback period without the programme is one year. With the programme this reduces to 0.8 years. A DSM programme for replacement of 60 W incandescents by 11 W CFLs is considered.

According to Nadel and Kothari 3.5% of the industrial lighting through incandescent lamps. From the HT survey figures we arrive at a connected load of 4.6 MW. Hence the total market is 77,000 lamps (of 60 W each). A peak coincidence factor of 60% is assumed and the number of operating hours is 3,000/year. Fifty percent of the capital cost of the compact fluorescent ballast is to be given as subsidy by the implementing agency. It is assumed that 20% of the eligible market is unwilling (Box 5.8).

Life of CFL (hours) = 8,000 Life of incandescent bulb (hours) = 1,000 Hours of operation (per year) = 3,000 Total market = 77,000 (60 W wach) Peak coincidence factor = 70% Cost of ballast Rs. 150 Cost of CFL Rs. 200 Cost of incandescent lamp Rs. 9.6 Electricity consumption for CFL 14 W Subsidy (% of ballast cost) = 50% Five year target (nos.) = 29,000 Simple payback period with programme (years) = 0.8 Simple payback period without programme (years) = 1.0 Cost of saved energy (RsVkWh) = 0.61 Programme cost (Rs./kW) = 2,900

Box 5.8. Compact fluorescent lamps

Table 5.10 shows the annual targets for the compact fluorescent programme. It is seen that the demand savings in the plan period is about 1.5 MW. This is equivalent to a cost of Rs. 2,900/kW saved for the utility. The total cost of saved demand, including the participant costs, is Rs. 6,300/kW. The energy saving in 1998 is 17.8 MU and the cost of saved energy is Rs. 0.61/kWh. The total number of adoptions of compact fluorescents is 38,710.

70 Table 5.10. Annual DSM programme targets for replacement of incandescents by compact fluorescents

Year Demand savings Energy savings Total adoptions Programme cost (MW) (MU) (no.) (Rs.million) 1994 0.26 1.16 3970 0.43 1995 0.45 2.0 5160 0.57 1996 0.7 3.14 6990 0.79 1997 1.05 4.7 9640 1.12 1998 1.5 6.8 12950 1.57 Total 1.5 17.8 38710 4.48

5.6.9 Replacement of magnetic ballasts by electronic ballasts (ELB)

Fluorescent tubes are widely used in industrial offices and often in shop floors. In textiles a large number of fluorescent tubes are used on the shop floor. Each tubelight fixture has a ballast which provides a high voltage to initiate the discharge and then limits the current. For our analysis, we consider a fixture for a single tube (each of 40 W rating). A conventional magnetic ballast for this fixture consumes about 12 W. Instead of a magnetic ballast, it is possible to opt for an electronic ballast which draws only 1-3 W. For our analysis we take an electronic ballast power consumption of 3 W, a life of 15 years, 3,500 hours per year operation and a 80% peak coincidence (Nadel and Kothari, 1991). The cost of magnetic ballast is Rs. 140 and of electronic ballast is Rs. 375. According to Nadel and Kothari (1991) 73.9% of the industrial lighting load is accounted for by fluorescents. Fluorescents in the HT industry would account for 100.4 MW of connected load (from the HT industry figures). This implies a total market size of 215,000 fluorescent tubes (of 40 W each). We consider only the replacement market as industries are likely to opt for an electronic ballast only when ballast replacement is due. Fifty percent of the incremental cost of the electronic ballast is to be provided by the implementing agency. It is assumed that 20% of the market is unwilling. The payback period without the programme is 3.2 years and with the programme is 1.6 years (Box 5.9).

Table 5.11 shows the annual targets for the electronic ballast programme. It is seen that 3.50 MW of demand saving is possible with this DSM option. A total of 0.396 million electronic ballasts will be required during the five year plan period. This is equivalent to about 40 ballasts/industry. The cost of saved demand for the utility is Rs. 12,000/kW. The energy savings in the terminal year of the plan is about 15.1 MU and the cost of saved energy is Rs. 1.00/kWh.

71 Life of ballast (years) = 1.5 Lighting load by fluorescent lamps 100.4 MW Consumption by magnetic ballast 12 W Consumption by electronic ballast 3 W Peak coincidence factor 80% Cost of magnetic ballast Rs. 140 Cost of electronic ballast Rs. 375 Subsidy (% of ballast cost) = 50% Unwillingness = 20% Five year target (nos.) = 2,64,000 Simple payback period with programme (years) = 1.6 Simple payback period without programme (years) = 3.2 Cost of saved energy (Rs./kWh) = 1.0 Programme cost (Rs./kW) = 12,400

Box 5.9. Electronic ballasts

Table 5.11. Annual DSM programme targets for replacing magnetic ballasts by electronic ballasts

Year Demand savings Energy savings Total adoptions Programme cost (MW) (MU) (no.) (Rs.million)

1994 0.35 1.55 28500 3.74 1995 0.76 3.3 47500 6.62 1996 1.36 5.94 71700 10.73 1997 2.24 9.77 103500 16.69 1998 3.50 15.1 144500 25.1

Total 3.50 35.66 395700 62.88

5.6.10 High efficiency fans and pumps

The efficiency of fans and pumps can be improved by using aerodynamically designed fans and improved impeller designs. A base unit of 20 kW is considered. The cost to retrofit a high efficiency fan (or an improved impeller) has been taken as Rs. 3,000 per kW installed. A conservative estimate of 15% saving has been taken. A peak coincidence factor of 80% and 4,000 hours of operation at full load have been assumed. The incremental maintenance cost is taken as 5% of the capital cost. The connected load for fans/pumps and other motors excluding compressers and refrigeration for HT industry of MSES was obtained at about 1474 MW. National Productivity Council (1991) estimates indicate that about 34% of this motor load is for fans and pumps i.e., 497 MW in 1989-90. This is equivalent to 608 MW in 1992- 93.

It is expected that about 50% of the pumps and fans are eligible for replacement by high efficiency fans and pumps. Hence, the total market is about 13,760 equivalent units of 20 kW

72 I

each. The programme envisages that 50% of the capital cost will be met by the sponsoring agency (Box 5.10).

Lighting load by fans and pumps 608 MW Peak coincidence factor 80% Cost of retrofit efficient fan (Rs./kW) = 3000 Subsidy (% of fan cost) = 50% Unwillingness = 20% Five year target (20 kW each) = 13760 Simple payback period with programme (years) = 1.1 Simple payback period without programme (years) = 2.2 Cost of saved energy (RsVkWh) = 0.77 Cost of saved demand (Rs./kW) = 8700

Box 5.10. High efficiency fans and pumps

The initial programme setup cost is taken as Rs. 0.2 million and the annual recurring cost is taken as Rs. 0.3 million. The payback period for the consumer with the programme is 1.1 years. It is assumed that 20% of the market is unwilling in the long run.

Table 5.12 shows the total adoptions, peak demand savings, energy savings and programme costs for high efficiency fans and pumps. During the five year period the peak demand saved by this option is 23.3 MW and the energy saving is 304.4 MU. The cost of saved demand for the utility is Rs. 8700 per kW. The cost of saved energy is Rs. 0.77 per kWh.

Table 5.12. Annual DSM programme targets for high efficiency fails and pumps

Year Peak demand savings Energy savings Total adoptions Programme costs (MW) (MU) (Rs.million) 1994 4.0 19.9 1278 23.7 1995 6.9 34.3 2199 32.9 1996 10.8 53.7 3446 47.9 1997 16.1 80.5 5166 71.0 1998 23.3 116 7500 102.4 Total 23.3 304.4 19589 277.9

5.6.11 Improved power factor correction

Industrial loads are usually inductive in nature and have a lagging power factor. Improvement of the power factor by adding capacitor banks can result in a reduction of the maximum demand required. The peak demand of the HT industry is approximately 400 kW per industrial consumer. We consider a DSM programme for improvement of power factor from the existing 0.94 to 0.98. The cost of capacitor is taken as Rs. 330 per kVAR. Each adopting

73 industry would also opt for an automatic power factor correction controller costing about Rs. 20,000. This programme results in a 4.1 % reduction in peak demand. The annual maintenance cost of the capacitor bank has been taken as 5% of the capital cost.

It is assumed that 90% of the industries are eligible (10% may already have power factor greater than 0.98). It is expected that 50% of the capital cost of capacitor and automatic power factor correction will be provided in the programme. The payback period with the programme is 1.1 years. The initial programme setup cost is taken as Rs. 2 million and the annual recurring programme cost is taken as Rs. 0.3 million. Twenty percent of the market is assumed to be unwilling in the long run (Box 5.11).

Cost of power factor correction controller (Rs.) = 20000 Maintenance cost (% of capital cost) = 5 Subsidy (% of PF controller cost) = 50% Unwillingness = 20% Simple payback period with programme (years) = 1.1 Simple payback period without programme (years) = 2.2 Cost of saved demand (Rs./kW) = 1000

Box 5.11. Improved power factor

Table 5.13 shows the savings in terms of peak demand reduction and energy. The effective peak demand savings during the plan period is 58.24 MW (actually demand savings should be expressed on a kVA or MVA basis, but we have converted it to MW savings at existing power factor). It is equivalent to a utility cost of saved demand of Rs. 1000 per kW. The equivalent total resource cost is Rs. 2100 per kW.

Table 5.13. Annual DSM programme targets for power factor correction

Year Peak demand savings Energy savings Total adoptions ■Programme costs (MW) (MU) (Rs.million)

1994 9.95 0 518 6.72 1995 17.13 0 892 9.32 1996 26.84 0 1397 13.46 1997 40.24 0 2095 19.93 1998 58.19 0 3030 28.66

Total 58.19 0 7932 78.09

74 5.6.12 Industrial cogeneration

Cogeneration implies the simultaneous generation of power and heat usually through steam. Cogeneration is both a supply option and a demand option. Cogeneration schemes have potential in textiles, paper, cement, fertilisers, sugar, chemicals and pharmaceutical industries. A Haigler Bailley study (Anon, 1987) estimated an economic potential of 880 MW for topping cycles in Maharashtra till 1996.

According to MSEB estimates 330 MW of net surplus power generation is possible from the existing sugar factories alone in Maharashtra in addition to meeting their own consumption of 24 MW. Added this to the Haigler Bailley estimate, we obtain 1,235 MW or 49% of the HT industry peak demand. We take a conservative estimate of 30% of the peak demand of the HT industries which results in an existing potential of 750 MW (Box 5.12).

Existing potential (MW) = 750 MW Initial capital cost (RsVkW) = 17,500 Installation cost for existing units (as % of capital cost) = 10% Variable cost (RsVkWh) = 0.40 Subsidy = 25% of capital cost Unwillingness With programme = 20% Without programme = 40% Five year target (MW) = 280

For existing units: Simple payback period with programme (years) = 1.4 Simple payback period without programme (years) = 1.9

For new units: Simple payback period with programme (years) = 1.3 Simple payback period without programme (years) = 1.7

Cost of saved energy (RsVkWh) = 0.76 Programme cost (Rs./kW) = 4,800

Box 5.12. Industrial cogeneration

The initial capital cost for a topping cycle cogeneration system is taken as Rs. 17,500/kW installed and the variable cost of electricity generation is taken as Rs. 0.40/kWh. For cogeneration in existing units an additional installation cost of 10% of the capital cost is taken. In the absence of a programme we assume that only about 40% of the cogeneration potential will be realised in the long run. In the programme 25% of the capital cost for the cogeneration system is to be borne by the implementing agency. A availability of 80% is taken. In the absence of a programme the payback period for existing industries is 1.9 years and 1.7 years for new industries. For cogeneration, a peak coincidence factor of 80% is considered. An average loading of 80% and an availability of 80% is taken. In the absence

75 1 of a programme, the payback period reduces to 1.4 years for existing industries and 1.3 years for new installations with the programme.

Table 5.14 shows the annual targets for the industrial cogeneration programme. The net demand savings in the terminal year is 323 MW. This is equivalent to a cost of saved demand for the utility of Rs. 4800/kW. When the participant costs are considered the cost of saved demand is Rs. 19,100/kW. The total installed MW is 307.5 MW. It increases from 38 MW in the first year to 57 MW in the terminal year of the plan. The cost of saved energy is Rs. 0.76/kWh.

Table 5.14. Annual DSM programme targets for cogeneration

Year Demand savings Energy savings Total adoptions Programme cost (MW) (MU) (MW) (Rs.million) 1994 71.8 403 38.8 198.3 1995 118.1 662 50 277.4 1996 174 976 68.1 402.4 1997 242.3 1358 93.6 593.8 1998 323 1813 57 856.0 Total 323 5212 307.5 2327.9

5.7 Synthesis of programmes: 5-year DSM plan

The sum of the DSM programmes constitutes a DSM plan. Table 5.15 shows the DSM programmes arranged according to the cost of saved demand for the utility. The programmes are aggregated with and without cogeneration.

Table 5.15. Five year DSM plan for Maharashtra - summary of results

DSM Option Demand Energy Savings Programme Utility CSE Rs/kWh Savings in 1998 cost Total (MW) (MU) (Rs. million) RsVkW RsVkWh resource

TOD 160 - 376 1700 - 2100 EAF 26 356 69 2000 0.20 7500 CFL 1.5 17.8 4.5 2900 0.61 6300 GHK 80 906.4 415 3800 0.86 11900 HPSV 1.6 29.1 13 6500 -0.10 9700 EEM 14.3 169.3 189 9000 0.63 17600 VSD 54.1 1260.7 196 10200 1.05 41100 VARS 16.2 301.3 219 10600 0.64 28000 ELB 3.5 35.7 63 12400 1.00 24300 PUMPFAN 23.3 304.4 278 8500 0.77 28000 PF 58.2 0 78.1 800 3200 Total 436.7 3380.7 1900.6 4300 0.82 12700 COGEN 323 5211.6 2328 4800 0.76 19100 Grand Total 759.7 8592.3 4228.6 4500 0.78 15900

76 The plan gives, without cogeneration, demand savings of 437 MW at a cost of Rs. 1900 Million. The average cost for the utility is equivalent to Rs. 4300/kW. The cost of saved demand for the utility ranges from 1700 Rs./kW (time of day tariffs) to Rs. 12,400/kW (electronic ballasts). For all the measures considered the capital outlay required by the utility is less than that for augmenting supply (by building central power plants), which typically costs between Rs. 30,000 and 40,000 per kW. When the participant costs are included, the total cost of saved demand ranges between Rs. 2,100 per kW (time of day tariff) to Rs. 41,100 per kW (Variable Speed drives). The total cost of saved demand for this plan is Rs. 12,700/kW and the energy savings by 1998 is 3381 MU (excluding Cogeneration). The average cost of saved energy is Rs. 0.82/kWh. The short run marginal cost of electricity generated by the state electricity boards in India is about Rs. 0.90-1.30/kWh while the long run marginal cost ranges between Rs. 1.77 and 2.02 p/kWh (Nadel et al., 1991). Actual values are likely to be higher as these costs are prior to Rupee devaluation.

The cost of saved energy ranges between Rs. 0.10/kWh (HPSV) and Rs. 1.05/kWh (variable speed drives). It is evident that the cost of saved energy is less than the short run marginal cost of electricity generation. Though variable speed drives are slightly costlier from the total resource point of view, its cost of saved energy is much less than the long run cost of energy generation. We have not considered the capacity utilisation factor for conventional power plants. If an average capacity utilisation of 60% is considered, the total cost of saved demand for the costliest DSM option viz. variable speed drives is Rs. 24,700/kW, which is less than the capital cost for conventional power plants.

When cogeneration is also considered, the demand saving is 760 MW at a cost (to the utility) of Rs. 4229 Million. The cost of saved demand is Rs. 4500/kW. When the participant costs are considered the total cost of saved demand is Rs. 15,900/kW. The energy savings is 8592 MU and the cost of saved energy is Rs. 0.78/kWh. Table 5.16 shows the physical targets to be achieved during the five year plan period (1994-98).

Table 5.16. Physical targets for DSM for 5-yar plan

DSM option Target Energy efficient motors 44,960 nos. Variable speed drives 8,870 nos. Good housekeeping/Time-of-day tariffs 3144 Industrial units Waste heat VARS 203 (100 TR machines) Improved EAF 37 Furnaces (of throughput 10 T each) HPSV 62.000 Fixtures Compact fluorescents 38,700 fixtures Electronic ballasts 396.000 nos. Power factor correction 7,900 units High efficiency fans and pumps 19,600 nos. Industrial cogeneration (installed capacity) 310 MW

77 5.8 Impact on peak demand

Once a DSM plan has been characterised in terms of its savings, market penetration, etc., the next step is to evaluate its effectiveness through demand reduction and energy savings. MSES’s peak demand during 1992-93 was 6,864 MW and, as the forecasts show, it will increase to 9846 MW, while consumption would be 62,100 MU by the year 1998. Tables 5.17 and 5.18 give the effect of DSM programme on the peak load and energy demand for the five year period (up to 1998). There will be substantial increments in peak demand and electricity consumption if the DSM programmes are not implemented. The savings from DSM programmes are 760 MW in peak demand and 8592 MU in energy demand.

Table 5.17. Effect of DSM on peak demand increment (MW)

Year Without DSM With DSM Peak demand increment Peak demand Increment Peak demand reduction Increment with DSM

(1) (2) (3) (4) 5 = (2)-(4) 1994 7418 554 145 79 451 1995 8037 519 246 101 453 1996 8600 563 375 129 434 1997 9202 602 545 170 432 1998 9846 644 760 215 429

Table 5.18. Effect of DSM on electricity demand (MU)

Year Without DSM With DSM* Increment with DSM Electricity demand Increment Energy savings Increment

(1) (2) (3) (4) 5=(2)-(4) 1994 46781 3489 614 334 3155 1995 50691 3910 1035 421 3489 1996 54240 3549 1562 527 3022 1997 58036 3796 2243 681 3115 1998 62100 4064 3381 1138 2926

* without cogeneration

5.9 Impact of DSM plan on environment

The implementation of DSM programmes helps reduce pollution over the baseline. The burning of coal in power plants pollutes the environment through the emissions of carbon dioxide, sulphur dioxide, nitric oxides and flyash. Also, the calorific value of the Indian coal is decreasing rapidly, thereby increasing its consumption per unit of generation. Therefore, the energy savings from DSM programmes will reduce the emissions significantly. The

78 quantitative assessment of various emissions associated with power generation in thermal plants has been done using the norms from Chattopadhay and Parikh (1993). Table 5.19 provides the details regarding the emission reduction. As can be seen from the table, the quantity of emission reduction in C02 will be 9,320,000 tonnes for the five year period. The S02 and N02 reductions will be 27,000 and 43,000 tonnes respectively in five years. The quantity of fly ash that can be reduced will be 260 tonnes.

Table 5.19. Emission reductions through the implementation of DSM plan

Year Energy savings Emission reduction (,000 tonnes) (MU) o $ 00 Flyash

A 20 year DSM plan for the HT industry sector considering the change in diifusion rate over time and long-run market share has been discussed in Parikh et al. (1994).

79 6 Barriers in implementation, institutional and financial mechanisms

In the earlier chapters, various measures have been discussed for saving energy and reducing associated pollution through the introduction of efficient energy technologies and demand side management. However, there are several barriers in implementation, and appropriate institutional and financial mechanisms are also needed before these measures are introduced. We discuss these issues in this chapter.

6.1 Identification of barriers

(i) Technical. Most of the power plant staff are engaged in day-to-day routine work and find little time to get acquainted with the latest developments in the area of power plant technology. Their exposure is limited to their own plants or occasional sharing of experiences with others. At middle and higher management levels this is achieved to some extent through transfer of officers. Thus, though competence and potential exist, there is no effective mechanism to ensure their exposure to the outside world and the upgradation of their knowledge. It is only individual initiatives that lead to some innovative studies here and there. This is also true of T&D staff. While the nature of work at power stations may make it a little difficult to spare employees for training, it is possible to make a beginning by having briefings by the expert group (for details refer (v) below). Training programmes can be planned in rotation. The improvement in quality of work and productivity through these measures can more than compensate for the reduced availability of employees at the plant due to training programmes. The programme design is important - it should emphasize problem solving. The training programme should also be supplemented by empowering of the employees to introduce productive changes.

In some cases technology availability and reliability is a barrier. This is true for some technologies currently seen as DSM options. Lack of technical expertise with consumers has also been found to be one of the barriers in the way of selection of alternate technologies. For example, the IGEDR DSM survey revealed that due to lack of expertise some industries were unable to decide on adoption of variable speed drives, efficient pumps and fans, etc.

(ii) Institutional. A proper institutional mechanism to take up issues related to upgradation of technologies in the plant does not exist. In some plants there may be an energy conservation cell or a group, but their major thrust is on reducing oil consumption (for example in the Nasik TPS). Success has been achieved in reducing oil consumption in the Nasik plant. But due to its narrow focus, the potential gains are limited. Further, even if a conservation cell is established in a plant, the approach is not very effective - for the cell members the work related to conservation is incidental to other routine jobs. Such cells are usually restricted to playing an advisory role. Significantly,

80 utilities do not have any institutional mechanism to formulate and implement DSM programmes.

(iii) Financial. Plant modernization is mostly carried out under the renovation and modernization (R&M) programme of the Government of India. Plants for R&M are identified under this programme at the all-India level and financial support is provided. This is a relatively slow process and the number of plants scheduled for R&M depends on the finances available with the funding agency (Power Finance Corporation), which in turn depends on budget allocations and funding from other sources for this purpose. Normally, very old plants are taken up under the programme and complete renovation of the plants is carried out. There is no specific mechanism to take up and support technological upgradations involving a few equipments in the plants. However, MSEB is a relatively dynamic utility, and some of the MSEB plants have taken up technology upgradation measures that have short payback periods (and low capital investment requirements). But for measures like VSD for ID fan and BFP where the payback period may be relatively long and investment requirements substantial, there is no funding mechanism, since the perceived gains are small. For T&D also, there is no financial mechanism for major upgradations except for small budgetary provisions.

DSM requires explicit financing mechanisms. In the developed countries, this is achieved by providing incentives to the consumers through utilities, and utilities are compensated through pricing policies. The cost of the DSM programme is thus met from the savings that accrue to utilities and consumers. This is a prerequisite for long term success of the programme; it should be able to finance itself. There is no financial mechanism currently in India to finance DSM programmes. Grants from financial companies like IDBI are made available to individual companies for energy audit purposes. But in the absence of a viable institutional arrangement, no financial mechanism for DSM measures exists. Currently, utilities have no interest in sharing their gains (if any) with the consumers, making DSM a financially non-viable proposition.

(iv) Pricing policies. The current power pricing policy is not conducive to promotion of conservation and adoption of DSM options. Rationalization of power tariff and introduction of measures like time-of-day tariff can help in realizing substantial energy and demand shiftings and savings. Some options (specially DSM) may need incentives and an initial push, through innovative measures such as revised pricing policies.

(v) Information and communication. MSEB is a large utility with several power plant sites with different vintages of power plant equipments scattered all over Maharashtra. MSEB has built up an information and communication mechanism for sharing experiences at different sites. Besides monthly meetings of all power plant chiefs at the MSEB headquarters at Bombay, engineers from different plants meet periodically to exchange ideas and share experiences related to problems and rectifications carried out. As a result, an improvement made in a plant gets replicated in other plants also. For example, ESP upgradation (pulse energization) and cooling tower fan blade profile rectification work was taken up in several plants as a result of exchange of such information. This is however, limited in scope. To enlarge the scope it may be

81 worthwhile to form a taskforce at the plant level for taking up the work related to rectification, periodic studies for upgradation of equipments and facilities, and their modernization. From time to time, the team should also visit other plants (especially technically modern plants) of MSEB and other utilities. At the apex level, a group with experts drawn from various power plants can periodically meet to share experiences, and visit various power plants for on-the-spot studies of possible upgradation. It is important that outside experts are also associated with this group. This type of set-up would ensure better quality proposals and faster communication. For the T&D system the expert group can be drawn from substations and also from outside.

In the case of DSM, lack of information about available alternatives for reduction of electricity consumption is one of the major barrier. This is true for consumers as well as utilities who cannot be expected to know about the electric equipments and their applications at the consumer ’s end. It needs a detailed study of current applications, scouting for new technological alternatives, restructuring of the system and process modification.

(vi) Managerial. Good housekeeping is one of the neglected areas in power plants as well as industries. Leaking steam, exposed high pressure and temperature steam pipings (due to damaged insulation in some places), air and water leakages in power plants are common phenomena that were observed during this study. Energy audit surveys of various industries have also brought out these shortcomings. Energy audit of plant auxiliaries is not carried out by the utilities and energy consumption (of auxiliaries) is not monitored (except for oil consumption). Proper training of staff regarding good housekeeping measures is required. Awareness campaigns, supported by hard facts and data can be educative and helpful in initiating these measures.

6.2 Recommended measures

In this section, we discuss the institutional and financial mechanisms required to implement environmentally sound energy technologies and the role that various agencies can play.

6.2.1 Institutional mechanisms

Some of the institutional mechanisms required to implement measures to reduce auxiliary consumption and DSM options have already been discussed in the preceding section. For reduction of auxiliary consumption and adoption of other measures related to plant technology upgradation, a task force with a target-oriented approach is required to be formed at the plant level. The task force should make periodic visits to other plants to share experiences. In addition to this, a high powered group consisting of experts drawn from various plants should interact with the task force at each plant and advise and help them in identifying actions to be taken (for technology upgradation), fixing targets and implementing them. The group should consider the overall power scenario, the operating environment and technological changes in the power sector, and work out short term and long term measures need to be studied and implemented. Its mandate should include visits to power plants outside the state,

82 and the country, if necessary, to keep the group updated on state-of-the-art in this area. The group should interact closely with power plant manufacturing, consulting and other such organizations (such as BHEL and NTPC) while formulating its plans and strategies, and share experiences with them. It should also have experts from outside organizations, industry, and institutes/universities. For T&D loss reduction, a set-up similar to the one proposed above for plant related activities would be needed.

Several types of institutional mechanisms are possible for DSM. One such mechanism proposed for India in different forums, is to have Energy Service Companies (ESCOs) that take up the task of implementing a DSM measure and recover the cost from the savings made by consumers on account of the DSM programme. ESCOs would require support through appropriate regulatory and financial mechanisms and power pricing policies. While isolated cases of success may emerge, pricing policy reforms and appropriate regulatory measures are prerequisites for the success of DSM programmes on a large scale.

A consortium approach, particularly in the initial phase of the DSM programmes in India, has also been proposed by several experts. The consortium would consist of representatives from organizations including utilities (MSEB in this case), IDBI (as financial organization), industry (specially from manufactures of efficient appliances and equipments) and association representatives (like *CII and ASSOCHAM), appropriate governmental departments and agencies like Energy Management Centre (EMC), and research institutes. The consortium could have a deeper involvement in the initial pilot project phase, and could subsequently be converted to a nodal agency for facilitating and disseminating DSM programmes. A pilot project is required to be taken up before ESCOs can independently handle the DSM programmes, to thrash out issues related to financial and regulatory mechanisms and pricing policies. While ESCOs could implement the DSM in specific industries/segments, the agency could address the broader issues like awareness, availability of technologies, standards and regulations required, and also ensure participation of all concerned in the programme. Based on the experience gained, it could also interact with governmental bodies on issues related to standards and regulations, specially for new industries, and work out innovative financial schemes. It may also have to be ensured that ultimately DSM is integrated with utility planning.

6.2.2 Financial mechanism

Reduction of auxiliary consumption through environmentally sound energy technologies benefits the environment through reduced emissions of CO2 (a greenhouse gas) and other pollutants like SO2 , NOx and particulates. Some of these technologies have small payback periods and low capital investment and can be taken up by the concerned utility. It is in the case of technologies or upgradations that have long payback periods and high investment requirements that financing mechanisms are needed. Theoretically, it is possible for a utility to prepare a plan for such upgradation and seek funding from financial institutions if the payback period is within acceptable limits. In practice, it may be difficult to get funding unless the utility is financially sound. Similarly, utilities do not have funds to support DSM programmes. Although there is some allocation of money for conservation programmes in the Eighth Five Year Plan, there is no allocation for specific programmes, nor a share of the allocation for utilities. Also, there is no institutional mechanism to decide how the money should be utilized and what type of programme should be funded. Part of this fund could be

83 allocated to utilities specifically for these programmes. Alternatively, utilities could be encouraged to submit proposals (with a consortium consisting of utility, industry (technology supplier), and experts) for funding in these areas.

Restructuring and reform of power pricing policies is vital to the success of conservation programmes. Policies can be framed in such a manner that consumers as well as utilities have incentive for conservation. Price reforms will not only help a utility to generate internal funds for such programmes, but also empower it to use markets to raise resources. Introduction of accountability for performance along with tariff reforms can help in increasing productivity of utilities, which would further improve their financial health. A utility in sound financial health would be able to tap the market for viable programmes.

DSM programmes need demonstration through a pilot project to establish their viability. Therefore, some incentive schemes and financial mechanisms may have to be worked out. Programmes like PACER of ICICI, EMCAT and INFUSE of HDBI can support such pilot projects. These funding agencies in turn may require funds for these programmes. International funding mechanisms and agencies like GEE, ADB, World Bank etc. can be approached for this purpose. These agencies can also be approached directly by the consortium for funding of specific projects. Considering the environmental perspective, the risk and uncertainty involved, and the high payback period of some of the options, GEE can at least fund a few demonstration projects. Once the viability of such a programme is established, it may be easier to raise resources from other sources. ESCOs would also be able to raise funds from the market and from banks, once the viability of these programmes is established.

6.2.3 Restructuring the utility

Several experts have argued for restructuring the utilities into different entities to segregate generation, transmission and distribution functions. This has benefit of efficient management of each function. Thus a generating utility would be able to concentrate more on reduction of auxiliary consumption to improve its generating capacity. Utilities responsible for different functions will have to be more efficient as inefficiency of one can no more be camouflaged by others, which is possible if all the three functions are combined in one utility. Other issues such as communication, technical expertize etc. can also be addressed by specialised utilities. However, overall system integration in this case may need automation and better coordination.

6.3 Recommendations for future work and role of various agencies

Based on the foregoing discussion on the barriers to DSM, and the institutional and financial mechanisms needed to overcome them, following steps have been identified for the next phase of work.

(i) Action by MSEB

(a) Formation of an expert group in MSEB at the apex level (in the corporate office/ planning department), responsible for drawing up short term and long

84 term measures for technological upgradation for plants and T&D lines, and conservation programmes including DSM. Experts need to be drawn from various plants and T&D zones/stations and outside organizations. For example, depending on area of expertise, experts from other utilities, NTPC, manufacturing organizations like BHEL, other industries, institutes/ universities, and governmental agencies like EMC can be associated with the group.

(b) Formation of a task force in each plant and T&D zone to formulate and execute the plan for the plant or T&D zone/ station, based on the recommendations of the expert group.

(c) Formation of a consortium consisting of representatives from MSEB, industry (equipment manufacturers), associations like CII, governmental agencies (like EMC), and a research institute working in this area, to initiate a pilot project for DSM.

(d) Commissioning a study on reforms required in pricing policies, and interacting with the state government for carrying out the reforms.

(ii) Actionby the State Government

(a) Providing the necessary information, policy guidelines and support for working out the pricing reforms by MSEB.

(b) Assistance in getting the recommended pricing reforms implemented, if necessary through legislation.

(d) Introduction of more autonomy and accountability through an MOU with the MSEB and if necessary, initiating steps to convert the board into a company for this purpose.

These measures are expected to not only tap the conservation potential that this study indicates, but go a long way in improving the overall working of the utility.

85 References

1. CMIE (1995). Current Energy Scene in India.

2. Economic Survey 1993-94. Economic Division, Ministry of Finance, Government of India.

3. Profile of Power Utilities in India (1993). Council of Power Utilities.

4. Annual Report on the Working of State Electricity Boards & Electricity Departments. Feb. ’94, Power & Energy Division, Planning Commission, Govt, of India.

5. D. Chattopadhyay, R. Banerjee and Jyoti Parikh, "Integrating Demand Side Options in Electric Utility Planning: A Multiobjective Approach", IEEE PES Summer Meeting 1994, San Francisco, CA, Paper # 94 SM 543-9 PWRS (To appear in IEEE Trans, on Power Systems).

6. Jyoti Parikh, B.S. Reddy and R. Banerjee (1994). "Planning for Demand Side Management in the Electricity Sector", Tata McGraw Hill, New Delhi.

7. Jyoti Parikh and S. Gokarn (1993). "Climate Change and India ’s Energy Policy Options", Global Environmental Change, pp. 276-291.

8. D. Chattopadhyay and Jyoti Parikh (1993). "C02 Emissions Reduction from the Power System in India", Natural Resources Forum, pp. 251-261.

9. J. Parikh and D. Chattopadhyay. "A Multi-Area Linear Programming Model for Analysis of Economic Operation of the Indian Power System", Paper No. 95 WM 122-2 PWRS, Presented in the IEEE Winter Meeting of Power Engineering Society at New York, February, 1994 and to be published in the IEEE Transaction on Power Systems.

10. J. Parikh, J.P. Painuly and K. Bhattacharya (1994). "Environmentally Sound Energy Development Strategies for the State of Maharashtra", report of the Phase 1 of the Project submitted to UNEP Centre, Ris0 National Laboratory.